Beach Energy Limited (BPT.AX) Earnings Call Transcript & Summary

Ladies and gentlemen, thank you very much for joining us today. Members of the executive team and I are looking forward to engaging with you today on the progress of delivery on the Beach strategy, our commitment to delivering material growth and our plans over the next 3 years across the business, including our commitment to a sustainable future. Before we start, let me first highlight that we respect the traditional custodians of Australia and New Zealand. We acknowledge that we're meeting today on the traditional country of the Kaurna people of the Adelaide Plains. And we pay our respect to their elders, past, present and emerging. We also recognize and respect their cultural heritage, beliefs and spiritual relationships with the land and acknowledge that they are of continuing importance to the Kaurna people today. Let me begin by highlighting the compliance statements. This is particularly important for an Investor Day as we will be making numerous forward-looking statements that are opinions, which, by their very nature, are not certain and are susceptible to change. I'll let you read the entire statement at your leisure. Today, we're going to update you on Beach Energy in a lot of detail. You have the opportunity to hear from 6 further members of the executive team. And we're all excited, frankly, to be able to share with you what we believe is a compelling growth strategy, a growth strategy that is in the execution phase with rather well and truly on the road. Today, we will cover strategy, sustainability, financials, our markets and each of our key assets and projects. You will then have an opportunity to engage in Q&A. We hope that you'll be pleased to hear that we've made significant progress with our strategy and the execution of our projects. For example, today, you'll hear some recent material upgrades such as, one, we've executed a heads of agreement with BP that covers all the material terms and conditions for BP purchasing all of our 3.75 million tonnes of LNG from the Waitsia Stage 2 project. We had term sheets from 14 customers, and we believe BP's proposal is compelling. Also, as you know, we've already commenced construction at Waitsia Stage 2. Two, we are 80% complete on the Geographe element of our Otway development project, progressing to refill the Otway Gas Plant and most importantly, the most challenging wells, Geographe-4 and Geographe-5, have both been drilled in line with pre-drill expectations. That's a significant positive. Three, we've completed our FEED studies on the Moomba CCS project where we have a 33% interest. We stand ready with the operator to assess the FID decision subject to commercial terms, and that project is a crucial part of supporting our net-zero ambition. More on those 3 points later, and we look forward to sharing many more examples of good progress on the execution of our strategy with you later today. Beach is well positioned for the future. Our strategy is clear. Our growth is being delivered and we have a clear line of sight to material carbon emissions reductions. Most importantly, we've built the team to deliver this in line with our values. As I said, you'll get a chance to hear from 6 of these executives today. And you can see from their profiles that we have built a first-class team with a broad range of capabilities and background. As they present today, we'll also share an insight into the caliber of teams sitting below Ian, Thomas and Sam. You'll see that in the past few years, we've deliberately created an extended leadership group, particularly within the technical disciplines that have extensive industry experience. Given our material growth program is well into execution, it's fair to say these teams are busy and they're energized. Critically, they're pleased to be engaged in the most important parts of our business, finding, developing and delivering our products to our customers. The key to what we'll be presenting to you today is a demonstration of a business that is focused on executing the strategy and therefore, delivering on committed growth objectives. To give you an early heads up, we'll be showing what the business looks like from today through to the end of FY '24. And that's just about 2.5 years away, just over. We'll focus on a base case that demonstrates what Beach looks like, excluding any exploration success or pre-FID projects with the exception of Enterprise. That is to say, we'll be demonstrating delivery of our committed pipeline of growth. This is different to the strategic outlooks that we've shown in the past, where we assumed exploration success and multiple further developments. We'll briefly make reference to further upside potential in the portfolio but it's not the primary focus of today. The base case is, therefore, not directly comparable to previous Investor Day information. So let's start off by highlighting the key takeaways that we believe you should get from today and clarify the nature of our growth strategy. The base business should deliver our FY '24 production target of 28 million barrels of oil equivalent or a 13% CAGR on the FY '22 midpoint. That is without any exploration success, including on the Western Flank and without any further FID projects. The exception to this is Enterprise, which has been drilled and is awaiting FID in a relatively low-risk pipeline development tieback to the Otway Gas Plant. Despite our reinvestment, our capital discipline means our balance sheet remains highly robust. Indeed, we don't see net gearing exceeding 10% with a reasonable product price outlook. Importantly, that means that by late 2023, we would have 8 gas plants in operation across Australia and New Zealand, delivering gas into 4 independent markets. This includes the short East Coast gas market and the international LNG market. Diverse gas sales will provide downside protection and reliable and steady material cash flows for the company. That means from FY '24, we have material free cash flow which provides us with several opportunities: reinvestment in the business, pursuing inorganic growth and delivering material dividends or other capital returns to our shareholders. The diversity of this portfolio and the steady stream of gas revenues allows us to have significant confidence in our future. Today, you'll also hear about some of our values, including our relentless focus on safety, having just delivered our safest year on record despite the challenges of COVID-19 last year. Just as important, of course, are our ethical standards, including our drive for a sustainable future. We have an aspiration for net-zero emissions by 2050. We've already been executing the projects to reduce our operated emissions. In addition, our 33% interest in the potential Moomba CCS project demonstrates that Beach is a company that expects to make a material step change as we progress through the energy transition in coming decades. For me, the proposition of an investment in Beach is very clear, and our plans have been consistent over the past 3 years. One, Beach is focused on expanding our share of the tightening East Coast gas market. Indeed, with our current committed projects, we expect to supply about 16% of the East Coast gas market by FY '24. As you'll see today, this is from robust and high-returning developments that aim to refill the spare capacity at our core gas plants for an extended period. Two, Beach will be participating in LNG growth through the Waitsia development via the North West Shelf facilities. Importantly, by entering the LNG game in this way, we're not exposed to the traditional risks of other LNG projects, being capital overrun with the construction of LNG plants, jetties, tanks and others. The Waitsia development has the benefit of leveraging the North West Shelf facilities that have a reputation second to none for a number of decades. Further, 60% of our project capital exposure is secured under a lump sum turnkey EPC contract with proven performer, Clough. Three, we're already well down the path of derisking the remainder of our development projects. In New Zealand, first gas has already been achieved on the Kupe compression project that has been delivered within budget and 2 weeks ahead of the P50 schedule. In terms of our plans at the Otway. To have that gas plant fall in the second half of FY '23, we're now 80% complete on the Geographe development uplift with both Geographe-4 and Geographe-5 wells coming in line with pre-drill estimates. We expect to take FID on the Enterprise development in the second half of this financial year with first production circa second half FY '23. Four, all of these developments and our reinvestment in the base business this year and next leads us to a diversified gas revenue stream from 8 plants across Australia and New Zealand. And that leads us to material free cash flow from operations from FY '24. Five, I'd highlight that our base case assumes no exploration success from the Western Flank oil program. This is despite our intention to drill up to 15 oil exploration wells this year. In short, we wanted to demonstrate how robust this business is without the need for Western Flank oil upside. As an aside, I'd highlight that we have in the past few weeks drilled 3 gas exploration wells on the Western Flank, and we've discovered 2 new unconnected gas pools. Six, lastly but certainly not least, we'll share more information with you today on our aspiration to reach net zero by 2050 and the material progress we're making, including through the potential Moomba CCS project. The Beach strategy has been clear and consistent over the past 5 years, and it remains that way. Our key pillars are as follows. One, we aim to optimize our core strategic assets by keeping them fuller for longer. In short, that means maintaining and increasing supply to 8 gas plants across Australia and New Zealand. In doing so, we intend to uplift our production to 28 million barrels of oil equivalent by FY '24, a CAGR of 13%. And again, that's before any exploration or development upside outside of committed projects and enterprise. Two, we intend to maintain our financial strength. As of 31 August, we were in a net cash position. And given the material and stable gas revenues we have, despite the material reinvestment over the next 2 years, we don't see net gearing moving above 10% with the current portfolio. Three, we've continued to strengthen our gas business. By reinvesting in our strategically positioned gas assets, we will have a 16% share of the East Coast gas market, approximately an 8% share of the New Zealand market and our first ever LNG sales expected in the second half of 2023. Four, as you know, we regularly assess inorganic growth opportunities. We used that approach to totally recreate the company in 2017, '18 through the Lattice acquisition, and we've made further bolt-on acquisitions when the metrics have made sense. We're always hunting, but we've got robust thresholds and no burning need to change the portfolio at this point in time. Five, as you'll hear shortly, we've made significant progress on the aspiration to be net zero by 2050, both through our operated and nonoperated endeavors. Put simply, it's the right thing to do, and we're acting accordingly. Importantly, executing on our strategy over recent years has created a diverse portfolio of high-returning assets with reinvestment opportunities and asset lives generally beyond 15 years. When you think about Beach today, we represent 6 production and development hubs and by the end of 2023, we expect to have 8 operational gas plants serving 4 markets. That spread of portfolio provides material opportunities and significant downside protection. That was a very deliberate move by the company in the past few years. The other execs, of course, will have much more to say on each of those assets later today. Okay. So I've been referring to a base scenario. Let's clarify for you what that actually means. As a scenario, this assumes that the post-FID developments in the Perth Basin and Otway Basin continue to progress as planned. We assume no other pre-FID projects progress with the exception of Enterprise, which has been drilled and is a relatively low-risk pipeline development to tie back to the wellhead at the Otway Gas Plant. We also assume the Cooper Basin JV 2P reserves continue to be produced and developed. Importantly, for the scenario purpose, we assume no growth from the Western Flank or from BassGas. Again, this is a scenario to show what the company looks like if we did not rely on exploration upside on the Western Flank. Even with the base scenario, we would still increase our production target to 28 million barrels of oil equivalent by FY '24, a 13% CAGR on the FY '22 midpoint. The main growth is spread almost equally across the development projects already underway in the Perth Basin and the Otway Basin. Keeping in mind that the end of FY '24 is just over 2.5 years away, further near-term upside beyond the base case is potentially available. For example, if Western Flank oil exploration drilling is successful, then that could lead to a material uplift in FY '24 production. Beach plans to drill up to 15 oil exploration wells this year, so our answer should be forthcoming in the near term. Further, other opportunities in Western Australia, Victoria, and New Zealand all have the potential to provide further upside, including some as early as FY '24. Importantly, from FY '24, the base scenario provides material cash generation from multiple hubs and therefore, it creates significant free cash flow. Over time, this free cash flow can be partially reinvested into further growth for longevity of the business. This includes keeping the Otway Gas Plant fuller for longer with the development of existing discoveries and offshore exploration opportunities, growing production at the Lang Lang gas plant and keeping it also fuller for longer. This is done through nearby drilling opportunities and/or the Trefoil development. Perth Basin, opportunities for expansion and exploration upside. And of course, further drilling and exploration success within the Cooper Basin. As I've already mentioned a number of times, Beach has deliberately positioned over recent years to be a material gas player across multiple markets. The takeaway for you today is that by the end of 2023, we'll be producing gas from 8 plants in 5 basins and selling into 4 markets, including global LNG. We're bullish on the ongoing need for gas. And the tightness in LNG markets, along with the looming shortfall on the East Coast, only reinforce our thinking. As our plans crystallize, we're targeting around 125 petajoules of net gas production by FY '24. I'm sure it won't take you long to pull out a calculator and work out the material range of revenues and cash that we'll be generating from that gas business. We're incredibly proud, of course, of our announcement yesterday that we've entered into a heads of agreement for the sale of all of our currently planned Waitsia LNG offtake to BP. The key elements I want to highlight from these are as follows: one, the HOA contains all material terms and conditions for BP to purchase 3.75 million tonnes of Beach's LNG from Waitsia via the North West Shelf development. Two, the terms of supply are aligned with our North West Shelf agreements. And importantly, we've built in flexibility around the commencement of supply in the unlikely event that we are delayed. Supply will be via Karratha, of course, on an FOB basis through the highly regarded North West Shelf facilities, where BP has long experience in offtake and can utilize its regional LNG shipping capability. And finally, the LNG price is linked to Brent and JKM with uncapped upside exposure to each. And it also includes some downside protection. However, it's not an S-curve. Having worked our way through term sheets from 14 customers, Beach is pleased to enter into exclusive heads of agreement with BP and to progress finalizing an LNG SPA by the second half of FY '22. From a personal perspective, this deal holds a special place for me. Twenty years ago, when I joined Woodside, I was first tasked to source ORO gas, or other resource owners' gas, to bring into the Karratha facilities. It's taken 20 years, but we finally got there. These Waitsia volumes represent the first material ORO deal to be processed through the North West Shelf. Moving to Slide 15. Let's reiterate a few key elements of what we believe to be the attraction of Beach at this point. One, we've locked and loaded for material production growth over the next couple of years. It's already underway, it's in execution, and it's derisking as we progress. Two, our balance sheet is rock solid. Even with the capital committed to execute the growth, we expect our net gearing to remain below 10%. Three, we are and we'll continue to generate material revenue and cash from our reliable and higher-margin gas business across multiple hubs, and that provides us with multiple future capital allocation opportunities. Four, while we're about to return to oil exploration drilling in the Western Flank, success is not required to deliver on the outcomes shown in our base case scenario. But of course, the upside potential remains. And five, finally, the downgrade in the Western Flank reserves in the first half of 2021. As a result of that, of course, our share price has been impacted. And we show a relevant EV over 2P chart relative to our peers for your consideration, and I'll leave it at that. In my recent discussions with investors, I'm routinely asked what are the risks of the growth program? How are we managing them and when does Beach derisk? The broader team will give you a lot more detail on each asset later. But in summary, I'd highlight that we've been actively derisking over the past 12 months. We've deliberately maintained a low gearing through the execution phase, and our 2 major developments have made strong progress. Firstly, in the Otway Basin, we've been committed to refilling the Otway Gas Plant ever since the Lattice acquisition, providing additional gas to the East Coast market. We've already drilled the most challenging wells in the program, Geographe-4 and Geographe-5, and they've been delivered in line with expectations. We've also had 2 exploration successes from 2 wells, including the game-changing nearshore Enterprise discovery. On the corporate front, of course, we delivered a favorable outcome to the Otway GSA price review arbitration. So in short, we've made good progress on the Otway program, and we're confident looking forward, as Thomas will talk to you about later. Secondly, on Waitsia, we've reached FID, as you know, at the beginning of this year. We've executed all required agreements with the North West Shelf and also with AGIG for backhauling gas through the Dampier to Bunbury Natural Gas Pipeline. We've also achieved all government and environmental approvals. We've just announced the heads of agreement to sell our LNG to BP. And importantly, we have no capital exposure to new LNG trains, jetties or LNG tanks. We're using the existing reliable North West Shelf facilities. Our upstream onshore plant is being built by Clough, who've already been engaged in the project for about 2 years. And finally and importantly, we have a lump sum turnkey EPC contract where 60% of the project costs are fixed. So as you can see, we are very comfortable and confident with the risk reward equation at Waitsia. And again, Thomas will have more to say on that later. The Beach team, as I mentioned earlier, has made very good progress on the sustainability front in recent years. Firstly, at the FY '20 result, we announced a target of reducing our operated emissions by 25% by 2025 compared to our 2018 benchmark. This 25 by 25 initiative has progressed well through multiple projects at our gas plants, and we now sit approximately halfway towards achieving the target. Secondly, for our Waitsia development, we elected to fully offset reservoir emissions from first gas. This is about 60% of the project emissions. And we're also assessing how we address the remaining 40%. Lastly and importantly, at the FY '21 result, we announced an ambition to reach net zero by 2050. The potential Moomba CCS project, for which we have a 33% interest will likely play a key role in achieving this outcome. Brett will talk to you more about that shortly. So before I hand over to Brett, let's take you through again what we believe are the key takeaways from today as we believe that Beach is very well placed to deliver on our growth targets. One, just taking account of our committed growth projects and excluding exploration success and pre-FID projects with the exception of Enterprise, we expect to deliver an FY '24 production target of approximately 28 million barrels of oil equivalent. As I mentioned, that represents a CAGR of around 13%. We're locked and loaded, and the execution is underway. And a reminder, when we talk about FY '24, that's just over 2 years away. Two, our balance sheet is rock solid with the company in a net cash position of around $50 million as at 31 August. Through the capital spend peak period over the next 2 years, we don't see net gearing exceeding 10% based on the current outlook. Three, we've deliberately created a diverse gas business. And by the end of 2023, we expect to have 8 gas plants producing from 5 basins. These plants will deliver gas into 4 markets, including a focus on the short East Coast gas market and the global LNG market. Four, the breadth of that gas business not only provides downside protection, it also provides a stream of stable and predictable cash flows. From FY '24, we expect to be in a position of material free cash flow, and that creates multiple forward capital management alternatives for the company. Five, last, but certainly not least, we're focused on being a sustainable company that can support the energy transition. We have a net zero aspiration, as you know, by 2050. We're already delivering emission reductions through our operated projects, and we have the opportunity through CCS at Moomba to make a material step towards our ambition. I genuinely appreciate your attention for the first session this morning. There's a lot of good progress happening at Beach, and we are very excited by the future of the company. I'll hand over now to Brett to talk more about sustainability and HSE. Thank you.

Thank you, Matt, and good morning, everyone. Thanks for joining us today. I'm Brett Doherty, Beach's Group Executive for Health, Safety, Environment & Risk. I've been with Beach for about 3.5 years now, essentially from when Beach completed the Lattice acquisition. On joining, my primary goal was to unite each of Beach's operating sites and projects at that time under a single risk management system. We then use this system to drive HSE performance towards 0 incidents. The goal also included building a strategy for corporate sustainability, both for the near term and to provide a long-term vision. The achievement of exceptional HSE performance always reflects a company's success in all of its operational activities. So with that, I'm extremely proud of the fact that we've just achieved our safest year on record and the performance continues. Safety at Beach is our highest priority and receives constant attention from board to field. So we're really proud of what we've done this year in this important area. Our recordable injury rate has improved by more than 85% over the past 6 years. It's been more than 1.5 years and 3 million work hours since we've seen a lost time injury. We've done this in the face of the higher risk profile that our busiest year represents work hour wise. It included conducting an offshore drilling campaign for the first time and the attendant personal safety risks that that involves. On the environmental front, performance has been steady. We continue to satisfy all regulatory requirements in circumstances that have been -- become more demanding for energy companies. After a number of years of exceptionally low spill volumes, we suffered an offshore spill of silicon-based drilling mud early in the campaign this year. The spill itself required no remedial cleanup as the product was seawater miscible and is not ecotoxic. However, we took permanent action to prevent a reoccurrence. This single spill represented 85% of our total spill volumes reported in FY '21. Our process safety performance continues to improve with only a single minor loss of gas containment across our entire portfolio last year. Material losses of primary containment events, I'm happy to say, have remained very low since 2018. We take assurance in our trend over the last years. Almost all the events reported have been low risk, low volume. And this has been the result of a more informed, better process safety reporting culture. So what have we done to achieve this? Moving to the next slide, you can see we launched a single, more comprehensive operations excellence management system in FY '21. It required, amongst other things, a targeted safety strategy to be established based on an analysis of previous injuries. We also introduced lifesaving rules that concentrate on removing fatal hazards from the workplace. We asked our staff and contractors through a safety culture survey where they believed we could improve, and it's worked. On Slide 22, you can see we continue to intensify our focus on ESG. We recognize that climate change is one of the most important global challenges of the century. Natural gas has a critical role to play as we lower our global emissions footprint. And as such, Beach's plans to strengthen our natural gas portfolio are consistent with global ambitions. Notwithstanding this, we accept we have a role to play in managing our own carbon emissions. Our aspiration to achieve a net-zero emissions footprint by 2050 based on our own scope 1 and 2 emissions has been laid out in our recent sustainability report. Our first 5 years are clearly delineated by projects designed to achieve a 25% reduction in our operated emissions by FY '25. We're currently working on quantifying the next 5-year tranche to 2030. Our equity emissions will be materially reduced by around 30% through our participation in the Moomba CCS project with FID expected soon. For the out years to 2050, we are examining emerging technologies that will be adopted should they be viable. Beach supports the federal government in its commitments to climate change targets. We've got a dedicated sustainability department tasked with further refining our sustainability strategy. Initiatives across a broad spectrum of ESG themes have been instituted. These include a strong track record in protecting cultural heritage and implementing biodiversity offsets where necessary, significant ongoing engagements -- community engagements, I should say, and contributions and the respective introduction and updating of the important modern slavery and indigenous participation policies. Going on to the next slide, another key objective for our sustainability department is a stewardship of a near-term emissions reduction target. A credible long-term emissions reduction aspiration must be underpinned by near-term quantified year-by-year emissions reduction plans. It shows we're serious. At the end of FY '21, we are halfway to meeting our 25 by 25 plan based on our yet to be audited numbers. Physical plant modifications and a conscious change in our approach to operations have contributed to this. For example, we've installed a mercury recovery unit at the Otway Gas Plant and that has eliminated process flaring. Likewise, flaring at BassGas has been eliminated on plant start-up by modifying the plant to reprocess off-spec gas instead of it being flared as the plant comes back online. Leak Detection and Repair, or LDAR, is an important program for any gas producer to instate. An LDAR program seeks to detect so-called fugitive emissions. These are small leaks of methane in the plant from valve, seals, packing flanges, et cetera. And these -- and fix these in a systematic way. That's important because 1 tonne of methane vented is equivalent to 28 tonnes of CO2 emissions. All of our sites now use advanced imaging technology to identify these otherwise undetectable small leaks. Now recently, there's been a discussion regarding scope 3 emissions. For energy companies like Beach, these are the emissions caused by our customers using our products, which have their own scope 1 and 2 emissions. The government's policy focus must remain on managing all scope 1 and 2 emissions, whether they be energy companies or end users. Our focus on scope 3 emissions is then redundant. It's important to note, therefore, that 78% of Beach's Australian natural gas volumes are sold to customers with existing net zero commitments. Moving on to Slide 24 on the Moomba CCS project. This represents an exciting opportunity for Beach to join the Vanguard companies pursuing this technology. The project will reduce CO2 emissions from the gas extraction process at the Moomba Gas Plant, representing about 60% of total emissions from the Cooper Basin joint venture operations. It will provide material low-risk CO2 abatement that can be implemented quickly. We expect it will be one of the last unit cost CCS projects in the world when operating and will be the second largest CCS project under construction globally. It represents an opportunity to reduce Beach's equity emissions, as I said before, by 30% once operational. The project benefits from using empty reservoirs compatible with receiving injected CO2 and a locally concentrated source of CO2 that can be easily collected from Moomba's existing gas plant vents. Learnings from the Moomba CCS project may potentially be deployed across other parts of Beach's portfolio. We've conducted extensive internal and independent assurance on the project. These reviews have included subsurface reservoir suitability, proposed injection well design and location, facilities design, cost and schedule, of course, an examination of project and commercial risks. The federal government is expected to approve CCS as a methodology eligible to earn Australian carbon credit units, or ACCUs, under the Emissions Reduction Fund in October. Following this, the project will be registered for ACCUs eligibility, and this is expected by the end of this year. And so with that, I'll hand over to our Chief Financial Officer, Morné Engelbrecht. Thank you.

Thank you, Brett, and good morning, everyone. Thank you for joining us today. I am Morné Engelbrecht, and I'm the CFO here at Beach. I've been with Beach now for just over 5 years, and I've been involved in the exciting transformation of the business from a single basin E&P company to the multi-basin diversified oil and gas producer you see here today. Today, I'm even more excited to be involved and focused on completing on the next phase of growth. Starting on Slide 26, I want to highlight to you that we have a very disciplined capital allocation process. We are focused on and prioritizing our capital to deliver on our major growth projects and doing so sustainably. This focus will enable us to deliver on our base production target of 28 million barrels of oil equivalent by FY '24. In doing so -- so it will also deliver stable, long-term and diversified material gas revenues across 4 markets, including an extension into LNG. Our current base already includes high returning stable gas revenues supported by CPI-linked domestic gas term contracts, which together with our supporting liquids business, helped to deliver free cash flow breakeven of USD 25 per barrel of oil equivalent in FY '21 before incorporating growth capital expenditure. Importantly, from FY '24 onwards, the base scenario provides material gas generation from 8 plants in 5 basins and selling into 4 markets. This is expected to generate significant free cash flow with price protected LNG sales further making up approximately 20% of our projected gas volumes by FY '24. Over time, this free cash flow can be partially reinvested into further growth or longevity of the business. This includes keeping the Otway Gas Plant fuller for longer with the existing discoveries and offshore exploration follow-up; growing production at the Lang Lang gas plant and keeping the plant fuller for longer as well as drilling nearby opportunities and/or the Trefoil project; Perth Basin expansion from exploration upside; and further drilling in the Cooper Basin. To further support our rock-solid balance sheet, we have refinanced our debt facilities, which increased our facility size to $600 million. In the production base case scenario, the balance sheet is never stretched. Net gearing is still forecast to remain below 10%, assuming current economic assumptions are maintained. Beach will also be in a position where sustaining plateau production and delivering additional growth within our portfolio, including the further opportunities in the Perth Basin, Taranaki and Otway Basins will be self-funded. Importantly, this does not rely on exploration success from the Western Flank oil assets. Surplus free cash flow above these commitments will also provide us with multiple avenues for capital allocation and distribution. We will also continue our disciplined and selective approach to M&A, which has been a successful avenue for growth and value driver in the past. Finally, the potential for capital return to shareholders is a discussion we continually have here at Beach and will become a priority once we progress through the current phase of development. Slide 27 highlights the strength of our base business, which has delivered impressive underlying average EBITDA margins above 65% over the last 2 years. These margins are expected to rise as the gas business volumes increase in materiality from 40% of revenue in FY '21 to more than 75% in FY '24. This will be delivered through the refilling of existing gas plants and the commencement of production from the low-cost Waitsia Stage 2 gas project. This strategy has the potential to deliver material gas revenue growth for Beach from FY '24 at high EBITDA margins, which will allow for material uplift in free cash flow. This will allow Beach to self-fund our reinvestment into the business, maintain plateau production through our gas plants and providing optionality for our capital management framework beyond FY '24. Slide 28 highlights how we have delivered on our strategy and positioned the company for growth. Cash flows generated from our core business have been reinvested into organic growth projects and M&A activity. The primary contributor to date has been the acquisition of Lattice assets in 2018. Once this phase of capital expenditure is complete, focus will shift to our capital allocation framework. As stated, we have a range of possible capital management options available to us, which are not mutually exclusive. It could include a review of our dividend framework where we have approximately $500 million in franking credits, which will allow us to pay around $1.1 billion of dividends fully franked. It could also include other capital management initiatives like buybacks if the share price remains suppressed. Also, we do manage our exposure to different markets and contracting into those markets carefully. The majority of our gas sales generate stable revenue under a combination of CPI-linked long-term contracts, oil-linked contracts with downside protection and the newly announced LNG heads of agreement price into Brent and JKM with uncapped upside exposure but both downside price protection as well. These managed cash flows support our base business activities and protect and cover the majority of all of our operating costs. Excess positive cash flow from the liquid side of the business at current prices provide upside to earnings but will reduce an overall influence in scale as we head towards FY '24. Hedging of our liquid volumes are not considered necessary when considering our growing and stable long-term gas and LNG revenue and a favorable Brent price outlook. As of 31 August, we are still sitting at a net cash position of around $50 million, which is consistent with our cash position as reported at our full year results. It's worth noting that this takes into account that we are in the middle of an offshore drilling campaign that commenced in April, that we commenced construction and ordered long-lead items for Waitsia Stage 2 project, the acquisitions of both the Senex Western Flank acreage and taking into other additional equity BassGas from Mitsui. The increased activity in the Cooper Basin and the completion of the compressor project in New Zealand. With this strong foundation, net debt is expected to peak at less than 10% over the next 2 years as we complete the offshore Otway and Waitsia-2 development projects. While some could call this lazy, this strategy has allowed us to ride out the oil market shock in FY '20, '21 and the lower-than-expected production from the Western Flank oil assets. Further supporting our strong and rock-solid base, we have moved to refinance our debt facility that was due to mature in November 2022. We moved now as we saw a great opportunity in the market with margins at record lows and a very supportive banking group. Just to put it in perspective, we have managed to upsize our facilities to $600 million, providing 25% more liquidity compared to our old facility; lowered our margins, we pay by 10% when comparing our new 3-year margin to what we currently pay; achieved a more corporate style facility agreement, which provides less covenants and more flexibility; and the total commitments we've received were more than double what we asked for. I want to take this opportunity to thank our banking group for their great support they have provided Beach and look forward to their continued support as we deliver this very exciting phase of growth. This refinancing increases our weighted average term to maturity to just over 4 years, with a larger portion of the facility maturing in late 2026. This provides us with liquidity of approximately $650 million with an unaudited cash balance of around $50 million and an undrawn debt facility of $600 million. Our liquidity is further supported by the increase in gas price across Cooper Basin and Otway Basin operations following the successful repricing of gas contracts from Origin, a $200 million to $300 million cash benefit over the next couple of years relating to the federal government's accelerated depreciation program, which I will touch on in the next slide, and the recent arbitration wins, which boosted our cash by around $40 million with a further estimated $20 million per annum reduction in our carbon cost for Kupe until the end of FY '24. Overall, the additional liquidity will support our growth investment over FY '22 and FY '23 and fully fund the program as we target 28 million barrels of oil equivalent by FY '24. As mentioned before, Slide 30 highlights the cash benefit Beach expect to see as a result of the federal government's economic recovery plan tax measures. Based on our assessment of capital expenditure commitments over the next couple of years, we now estimate the cash benefit to Beach to be within the range of $200 million to $300 million over FY '22 and '23. This is around 25% higher than the previous range due to the reassessment based on when assets will be ready for use. The range is wide as it's based on a number of factors and circumstances. Ultimately, it will depend on Beach investing the capital to realize the benefit. There are also stringent legal criteria needed to be met for each individual asset. To be eligible, the asset must be installed and ready for use before 30 June 2023. In addition, Beach must not have committed to the expenditure on that asset before the tax measures were announced on 6 October 2020. The lower end of the range will be realized mainly through the investment in the Cooper Basin. The upside of the range would be supported through the Waitsia Stage 2 project being constructed and ready for use by 30 June 2023. The offshore Victorian Otway drilling program is largely not eligible as expenditure was committed to before the 6 October announcement date. The timing of this cash flow benefit is approximately 30% in FY '22 with around 60% to 70% being realized in cash in FY '23. This, therefore, has the effect of providing a liquidity boost at the same time as we're investing and delivering our growth. Together with the successful refinancing further reinforces the fact that our growth is fully funded. There will be no impact on our accounting profit and will essentially reduce our cash tax payable over the next 2 years. This economic recovery mechanism introduced by the federal government supports Beach as we focus our capital investment across our key growth assets, supporting jobs in an uncertain environment. Slide 31 shows our FY '22 capital investment guidance together with our current forecast for capital investment for FY '23. The FY '22 guidance of $900 million to $1.1 billion remains unchanged. Our capital investment revolves around the offshore Otway and Waitsia Stage 2 project developments, which make up roughly 45% of our CapEx spend; the drilling of up to 90 wells within the Cooper Basin JV to boost production levels from FY '22 onwards; the recommencement of exploration drilling activity in the Western Flank of up to 15 oil exploration wells this year; progressing FEED activities for Trefoil project; and undertaking 3D seismic acquisition across offshore Bass Basin. It is worth noting that FY '23 capital remains flexible as several proposed projects remain subject to final investment decisions, Board approval and our capital allocation process. These projects include the Trefoil project, which is currently in the FEED phase; Moomba CCS, which we are progressing through to FID; the potential Cooper East development well; and also looking at the commencement of the exploration and appraisal drilling program in the Perth Basin. Importantly, as we have highlighted in the previous slides, even investing in further growth in each of FY '22 and FY '23, net gearing is expected to remain below 10% over this period. So overall, the company moves into the final stage of our growth agenda in an excellent financial position. We look forward to working through the wide range of capital management options available to us once the increased gas revenue start flowing into our coffers. With that, I'll hand over to Lee who will run through our key markets in more detail.

Good morning, everyone. It's great to be here today. I'm going to talk to you about our markets, in particular, our gas markets. It's been an interesting year. Based on the energy news headlines, analyst commentary, policy statements and a seemingly endless stream of conference promotions I get in my e-mail inbox, one could be forgiven for assuming the world already runs on hydrogen. A spoiler alert, it doesn't. Not yet at least. While everyone has been busy drawing up their hydrogen road maps, a few important things have been happening in the natural gas industry. Firstly, over the northern winter, LNG spot prices hit record highs exceeding USD 30 an MMBtu. This was due to unexpected freezing temperatures and the resultant increase in short notice demand for uncontracted LNG and constrained shipping capacity. Now this looked at the time just to be an unlucky confluence of low probability events. Just to be sure, though, LNG importing countries came out of winter with plans to prudently replenish stocks in storage by buying LNG over the shoulder seasons when prices were expected to be lower. That didn't exactly work out as planned. Here we are at the start of autumn in a shoulder season, with Asian spot prices above $25, European storage at only 70% capacity and Chinese LNG demand continuing to increase year-on-year. Here in Australia, we saw the dramatic increase -- the dramatic impact rather that unplanned outages of coal-fired capacity can have with domestic gas price spiking above $30 per gigajoule during winter. In New Zealand, where around 80% of electricity is typically generated by renewable sources, more coal is being used for power generation than in recent history. This is despite aggressive carbon targets and policies. Now don't get me wrong. I'm very pleased both as an individual and as a father to be seeing the transition to a low-carbon world take off in earnest. But I'm also pragmatic. The road is going to be long and bumpy, and these recent events are a reminder about the criticality of alternate sources of energy to supplement renewables on the journey. At the top of that list is natural gas. We're proud to be a provider of this critical energy in 4 exciting markets. Firstly, in our largest market, the East Coast gas market, we've currently got a market share of around 12% but expect this to increase up to 16% by FY '24. In the Victorian Otway Basin, along with our joint venture participant, O.G. Energy, we're spending over $1 billion to bring new supply to the market and maximize the use of our facilities. Last year, our average realized weighted average price was over $7.50. We reported a favorable arbitration outcome for the Otway gas price review and the forecast domestic supply fundamentals are not getting any better with LNG imports expected to be needed sooner rather than later. Basic supply and demand is expected to provide ongoing support for prices even with suppliers such as Beach doing all we can to get as much gas as we can into the market every day. On the West Coast, we currently represent a smaller portion of the market with our supply from Xyris and Beharra Springs. This is expected to increase, however, post our LNG export period and potentially before then dependent on exploration and appraisal activities that Sam will discuss a bit later. The long-term Western Australian market fundamentals are forecast to be supportive of gas supply. And we already see signs of market balancing, which I'll discuss shortly. Over in New Zealand, our operated Kupe project is critical for domestic supply, representing about 15% of the market, with Beach's net share being half of that. The project also delivers 50% of New Zealand's LPG. Critical supply when you consider that the South Island is not on a reticulated gas network. With no new exploration permits being issued and supply from existing fields in decline, there's strong market support for any incremental supply we can develop. We're very pleased to be bringing the Kupe asset back to full utilization on completion of our compression project that Thomas will talk about. Lastly, I'm very proud and excited to be able to talk about our fourth and newest market, the global LNG market. Last year, we did what many thought was not possible. We secured deals with the North West Shelf, the Dampier to Bunbury Natural Gas Pipeline and the West Australian government to have Waitsia gas liquefied in Karratha and exported as LNG. Today, I'm equally as pleased that we've announced that we've agreed key turns with leading global LNG player BP for the supply and offtake of all of our equity LNG from the project. Turning now to look at the East Coast in a little more detail on Slide 34. Now I'm not going to labor that AEMO forecast and consensus views that we all know and agree on. Domestic supply is not expected to be able to continue to meet demand. What I will highlight, however, is how quickly this might be coming at us. AEMO have said that, and I quote, "If Port Kembla gas import terminal project commissioning is delayed, southern supply scarcity risks have emerged for winter 2023 under certain conditions and that these risks appear 1 year earlier than projected last year." This is corroborated by the ACCC, who, last month, in their July interim report, warn that for southern states in 2022, demand is forecast to be 6 petajoules greater than forecast gas production and withdrawals from storage. And that in previous year, potential shortfalls in the southern states could largely be met by flows from Queensland. However, Queensland producers are currently forecasting to supply only just enough gas into the domestic Queensland market to meet local demand. As I previously presented and consistent with all the analysts' reports I've seen that comment on the topic, the import of LNG to the East Coast is not expected to supply gas for less than $10 a gigajoule. On this slide, I refer to a JPMorgan report that estimated LNG imports in April would have cost around $11 a gigajoule. Now that's whether from Asia or the U.S. At that time, spot Asian LNG JKM was trading below USD 8 an MMBtu and U.S. gas Henry Hub was less than $3. Today, JKM is over $25 and Henry Hub above $5. These are significantly higher than when the implied import price of $11 was in April. Importing on a long-term Brent link contract wouldn't help either, with Brent currently over USD 75 a barrel. As we've said before and say again today, we continue to strive to get every gigajoule we can into this market, but Beach alone won't change these fundamentals. As the market shortfall emerges or the marginal prices set by LNG imports, we continue to be increasingly exposed to market prices through GSA expiries, contracting of new volumes from discovery such as Enterprise and price reviews. This is demonstrated by the chart in the bottom left of the slide. Moving to Slide 35 and LNG markets. We've shown before the industry expert forecasts of supply and demand and expected market tightening until supply catches up after 2026. What's changed recently though is the crunch we are experiencing right now before the northern winter has even started. Europe is phasing out coal and nuclear in Germany. Storage inventories are at record lows. Germany and the EU have their feet on the hose of expanded Russian imports via Nord Stream 2, and China is importing more LNG than ever. This all leads to not only extremely high spot prices of over $25 an MMBtu but also increasingly higher price expectations over the coming years. This is demonstrated by the chart on the slide that shows how the JKM forward curve has been stepping up across its entire duration over the recent months. Now while these price signals should only hasten new LNG developments to achieve the balances forecast post 2026, especially from the U.S., barriers to new developments are increasing. There's less traditional debt and equity capital available for hydrocarbon developments. Buyers are not taking the price risk they did in the first wave of U.S. LNG projects and President Biden's support for expansion of the industry is unclear, requiring federal permitting decisions to explicitly consider the effects of greenhouse gas emissions. Pivoting West, Slide 36. Once again, we've previously shown the AEMO supply demand forecast demonstrating an expected market tightening later in the decade, I'm not going to show the charts again but in summary, in December, AEMO stated that the West Australian domestic gas market is expected to be well supplied until 2026 and finally balanced until 2028. While this still appears broadly to be a reasonable assessment, we are already seeing signs of a more balanced market than we were last year. Effective cessation of supply from the North West Shelf post expiry of their GSAs is shown in the first chart. It's the dark blue wedge as a portion of the total market supply in light blue. Coincident with this, we've seen increases in reported spot prices shown in the second chart as well as signs of a more balanced market from our direct engagement with customers. Last but not least, on Slide 37, 1/3 of gas produced in New Zealand goes into power generation. And this is where the short-term marginal gigajoule produce goes. Renewables dominate this electricity market, typically supplying at least 80% of the country's power needs with the largest supply source by far being hydro. This is fantastic but the system needs flexibility when rainfalls are lower than average. Other renewable capacity, primarily geothermal and wind, cannot be instantaneously increased on demand. What we therefore see is an inverse relationship between hydro output. This is the red line on the top right chart and gas and coal-fired power generation, the stacked blue wedges on the chart. When there's less rain and therefore, less hydro, more gas and coal is consumed. Now all else equal, New Zealand would rather consume the less carbon-intensive of the two, which is natural gas. Domestic gas fields are declining, however, so they're left with no choice but to use coal, which unlike gas, can also be imported when it's needed. This is currently the case with New Zealand importing coal from Indonesia. It can be seen on the chart that coal-fired generation has increased materially compared to historical levels, and the gas has not been used to make up for the lower hydro capacity as it has in the past. Coal is being used instead of gas. In addition to being more carbon-intensive, coal is also currently expensive. So price certainly does not appear to be incentive for this choice. It appears to be the scarcity of available gas. These observations are supported by the data. The second chart shows gas production, the light blue line declining over the past year; while reported wholesale gas prices, the dark blue line, have been increasing. This demonstrates the criticality of nonrenewable sources to the energy mix, a dynamic that we expect to persist over the life of the Kupe field and that provides strong fundamental support for any further gas that we can develop around this asset. Now we're going to take a 15-minute break. Please stay on the webcast to join our execs, Ian Grant, Thomas Nador and Sam Algar, to hear more about the future of our assets. That was a 15-minute break. Thank you. [Break]

Welcome back, everyone. We're about to turn one of the key areas of our business in operations and then we'll follow that with a focus on development projects and exploration. So you're about to hear from the 3 key lead technical executives. And in the first instance, I'll hand you over to Ian to focus on operations. Thank you. [Presentation]

Good morning. I'm Ian Grant, Chief Operating Officer at Beach. I've been COO since July last year and responsible for managing the company's infrastructure, including maintenance and daily operations. I also oversee key operational programs, including the offshore drilling program we are currently undertaking in the Otway Basin. As you saw in the video, the offshore drilling program is well and truly underway, and we're in the final stages of drilling the Geographe-5 well before moving to the less complicated Thylacine wells. As a matter of fact, I was in the Ocean Onyx less than a fortnight ago and was able to witness firsthand the drilling operations underway. It's always exciting to see the scale and complexity associated with an offshore drilling facility. At the moment, there's also added complexity due to the changing border restrictions, and we're mitigating that by providing 3 different routes to the rig to minimize stress to our teams as much as possible. The team on board are doing an outstanding job, and I think it's fair to say they're happy to be moving into the warmer months and the likely improved weather conditions. Moving to Slide 42, and you can see we put together an experienced operations leadership team at Beach, with a proven track record in drilling operations, asset management, projects and commissioning. The team has significant global experience in multiple jurisdictions and environments across a wide variety of organizations. As you'll see, the general managers in charge of our key operations each have more than 20 years' experience. This highlights the impressive personnel that are operating our significant asset base. As you can see on Slide 43, Beach's interest in 8 gas plants across Australia and New Zealand at various stages of the life cycles from under construction to mature. As Matt highlighted earlier, we're currently in the execution phase of delivering on our strategy to maximize utilization across the facilities. Under this strategy, Beach is targeting increasing utilization across our 8 gas plants by FY '24. Our operating facilities include the Otway Gas Plant and Lang Lang Gas Plant in Victoria, the Kupe Gas Plant in New Zealand, the Beharra Springs Gas Plant in the Perth Basin and the Middleton Gas Plant on the Western Flank of the Cooper Basin. We are extremely proud of these facilities, and we continue to seek operations to increase utilization and maximize value. We are confident in our ability to build and commission new projects and have shown ability to commission them safely and efficiently whilst we maintain reliable operations, ramping up production through to 2024. Importantly, we have successfully and seamlessly delivered major plant turnarounds previously at the Kupe Gas Plant and more recently, the Otway Gas Plant since we acquired the majority of these facilities from Origin in FY '18. Not only were these shutdowns delivered safely and efficiently, but they also included a scope to support the new projects coming online. I'm now going to provide a deeper dive into some of the key assets, showing examples of how we're adding value in terms of reliability and efficiency as well as reducing our carbon emissions. At Otway Gas Plant, we're preparing to bring the Geographe-4 and Geographe-5 wells online. We completed a highly successful turnaround at the end of last year to ensure the facility was ready to handle new production volumes from the middle of this financial year. Importantly, during the turnaround, we undertook major works to prepare for the production uplift, which means there's no requirement for a major plant turnaround for the next few years. The project included a 22-day execution phase, including more than 40,000 man hours over 100 workers on site, any one time, and this was all delivered on time with an excellent safety performance. Even more impressively, this was undertaken during a state of disaster in Victoria due to the COVID-19 pandemic. I'm very proud of what the team was able to achieve on this project despite these extremely challenging circumstances. Through our maintenance transformation project, we to further optimize maintenance requirements which will support additional cost reduction at the plant. This work includes opportunities that aim to reduce plant downtime while improving reliability and maximizing plant throughput. Across in Kupe in New Zealand, we're in the final stages of commissioning the inlet compression project, with first gas already delivered 2 weeks ahead of schedule. We are on track to return the plant to full utilization in the coming weeks. Thomas will talk more about that later on in the presentation. We're also applying the maintenance transformation project at Kupe to ensure that future maintenance programs are optimized. As I mentioned, we executed a major plant turnaround at the Kupe facility in FY '19, and that provided us the opportunity to install tie-ins for inlet compression. We also completed all of the major integrity inspections. The turnaround was completed on schedule, including over 75,000 man-hours and completing more than 300 major activities within the scope. Once again, I'm really proud to say the project was delivered with an excellent safety performance. This is a credit not only to our team, but also our contract partners. We're also working to optimize the frequency of major turnarounds through a risk-based approach, moving away historically from a strict time-based approach to risk-based. This helps reduce capital oil expenditure over the life cycle of the asset. In the Cooper Basin, we continue to look at value-adding opportunities across our significant acreage on the Western Flank and cost reduction opportunities with Santos. Our Western Flank oil fields will be supporting the current development and exploration campaign with plans to pre-lay flow lines and infrastructure. This allows us to reduce connection times for new wells and accelerate first production into the Moomba network. In our Western Flank gas fields, we're looking to add perforations to some of our existing wells. This will support plateau production rates through the Middleton plant. With Santos and the Cooper Basin, we're looking at cost-sharing initiatives that benefit both parties and also support emissions reduction. This includes replacing imported diesel fuel with locally produced crude. We've also established a shared helicopter emergency medical service that allows us to share the cost and also improve the quality of the service. At Beach, we are continuing to review and undertake projects to lower our carbon emissions across all of our facilities. This is part of our core business through operations excellence, and it also supports our 25 on 25 (sic) [ 25 by 25 ] emissions reduction target. An example of this is shown Slide 47, where we have recently installed mercury removal facilities into the regenerative gas circuit at the Otway Gas Plant. This removal of mercury from the regen gas has resulted in a significant reduction of flaring over the life of the asset. It also reduces the emissions of mercury from the system, and it also provides debottlenecking of the Otway Gas Plant with a benefit of up to 14 terajoules per day. In addition to lowering emissions, these initiatives are also reducing downtime, and as you can see from the previous example, increasing production in some cases. We have many more of these value-accretive projects at varying stages of the planning cycle, and we look forward to sharing more of these with you in our sustainability reports in the future. I'll now pass over to Thomas who will talk to you about our development projects.

Good morning, everyone, and thank you again for joining us today. I'm Thomas Nador, and I'm the Group Executive of Development here at Beach. I've been with the company for 2 years, having come on board initially to help get a Waitsia Stage 2 LNG project sanctioned with Mitsui. We achieved final investment decision on this transformational project 8 months ago. And I'm pleased to say the project is progressing well. A little bit more on that later. I've been in my current role since February and I'm accountable for delivering our current growth project. With the help of Sam Algar, I'm also responsible for filling the hopper with our next tranche of development. Prior to Beach, I've spent 25 years working on projects from discovery to production across onshore and offshore, including 4 LNG developments. I've done this on both sides, being on the engineer and constructor side early in my career, and the owner's side over the last 2 decades. Beach has built a significant execution capability to deliver a development portfolio. This includes investment in people, processes and technology to support our execution objectives. 4 of our projects are in construction, 2 are in front-end design and the rest are in concept selection. The diversity of project maturity requires different skill sets and expertise. I'm really pleased to say that we have been able to attract the right level of project leadership experience to help us deliver. Our main high-returning project in the Otway and Perth basins are designed to provide near- to midterm production uplift, totaling more than 9 million barrels of oil equivalent by FY '24. And -- With a combined installed cost of between $1.9 billion and $2.2 billion gross, these developments are fully committed, funded and resourced to deliver production from as early as mid FY '22. Early production will come from our offshore Geographe program before first gas is delivered from the offshore Thylacine program, and then the nearshore Enterprise project. Over in the west, our Waitsia Stage 2 project will deliver gas to the North West Shelf and is expected to fill our first LNG cargo in the second half of 2023. The next 2 slides show at a high level, a key objectives to achieve by FY '24. These objectives are designed to maximize value from our assets across 5 basins highlighting both committed and uncommitted activity. I will spend more time on the details of these as well as our other development shortly. But in summary, we have a busy couple of years ahead to keep our 5 operated and 3 co-operated plants full by FY '24. From the greenfield Waitsia project in Western Australia, the offshore Otway campaign on the East Coast to the Kupe compression project in New Zealand, we are executing a gas growth strategy across our [ portfolio ] basin. The Waitsia project has commenced site construction ahead of schedule and is due to commence development drilling in the second half of FY '22. The program is progressing to plan to deliver first gas to the North West Shelf in the second half of 2023. You will later hear from Sam Algar in the presentation about the prospectivity of this basin. In the offshore Otway, our Geographe program is 80% complete with first gas from this phase of development scheduled for mid-FY '22. Our 2 Geographe production wells are drilled and are currently being completed. In the next 3 months, we will commence the drilling program for our 4 additional Thylacine production wells with first gas from this phase of the development expected in the second half of FY '23. Long lead item procurement has commenced with 80% of the key packages awarded. In parallel, we are also progressing FEED for the Enterprise time project. Following this nearshore liquids-rich discovery only 10 months ago, we are well progressed towards a final investment decision in the second half of this financial year. This, essentially, is an onshore pipeline project with first gas also expected in the second half of FY '23. Together, the Geographe, Thylacine and Enterprise projects are scheduled to return the Otway gas plant to capacity in the second half of FY '23. At Kupe, we have now completed all mechanical construction and pre-commissioning work and have reached ready for startup and first gas on this project. We are in the final stages of commissioning the new compressor and process system. This project will increase production of the Kupe facility to 77 terajoules a day and stay on plateau until FY '24. We are, of course, reviewing opportunities to extend this plateau beyond FY '24, and more on this from Sam later. Over to the Bass Basin, we are progressing FEED activities for our potential Trefoil development. This is aimed at extending the life of the Yolla and Lang Lang infrastructure and bringing additional gas supply to a tightening East Coast market. We will be acquiring a 3D seismic survey later this year to improve the imaging over the Trefoil field. Seismic processing will commence in the first quarter of next year, which will help inform a final investment decision in FY '23. This will also consider future tieback options for our White Ibis and Bass discoveries. On the Western Flank, we are focused on the measured deployment of capital to maintain production with exploration activities expected to resume during the second half of FY '22. So let's take a look at the Victorian Otway. As it happens, I spent 4 years on the first phase of this development with Woodside, when I worked on the project from concept selection through to first gas. As a testament to the prospectivity of the Victorian Otway Basin, we are now executing the fourth and fifth phases of the development with plans underway for future potential phases. The existing offshore assets consists of a Thylacine wellhead platform that sits on a still jacket structure in 85 meters of water, some 70 kilometers off the Victorian coast line and 80 kilometers from the Otway gas plant. At the time of installation, it was the deepest water-depth jacket placed by a jackup rig in the world. The platform is connected to the Otway gas plant via a 20-inch gas pipeline and a 4-inch service line. And these will remain in place for future phases. From a wells perspective, the Thylacine gas field currently consists of 4 production wells connected to the platform. The Geographe gas field consists of 1 subsea production well, Geographe-2, connected to a subsea manifold with an umbilical to the platform and a flow line to the existing offshore pipeline. Looking at our current program, we have already drilled an exploration well at Artisan 1 in March this year, which was a gas discovery. We have also drilled Geographe-4 and Geographe-5 production wells [indiscernible]. These will then be tied into the Thylacine platform, mid this financial year, using a reasonably simple rigid piping arrangement. Before the end of this calendar year, we will also commence drilling 4 additional Thylacine production wells, which will complete the currently committed drilling program. Connecting these wells to the platform will require additional flow lines, umbilicals and subsea structures. Contracting for these items is either completed or well advanced to support first gas in the second half of FY '23. In conjunction with our Artisan gas discovery, future tie back opportunities include La Bella and other exploration opportunities. This provides us with additional optionality for extending plateau production at the Otway gas plant. Our asset strategy for the Victorian Otway Basin is centered around maximizing the value of the Lattice acquisition by returning the Otway gas plant to full utilization. The work we are progressing is designed to effectively double production at the plant from the current levels up to 205 terajoules a day. With 85% of our 70 million barrels of oil equivalent of net 2P reserves undeveloped, the Victorian Otway Basin is a cornerstone of our East Coast gas growth strategy. You will also hear from Sam about their plans for measured offshore and nearshore exploration designed to maintain plateau production at this rate for the next decade. Volumes from Enterprise, La Bella and new discoveries can be marketed independently from current gas sales arrangements. The multiyear $1.1 billion to $1.3 billion gross program is split across 2 phases. As referenced previously, the first phase is focused on getting additional early production from the Geographe field by drilling 2 production wells and connecting these wells to the existing Thylacine platform. We are 80% complete on this phase. The second phase involves the drilling of 4 Thylacine production wells, 40 kilometers to the south of Geographe and connecting these to the Thylacine platform. Using the Diamond Ocean Onyx rig, a 100-tonne, 100-meter by 100-meter semisubmersible rig, we have now drilled and are in the process of completing both Geographe production wells. Both these wells have reached their respective reservoir targets, and are in line with pre-drill expectations. And therefore, we anticipate they will deliver gas as per our forecast. In parallel with drilling, our contractors have been fabricating and delivering subsea Christmas trees to support both Geographe and Thylacine tiebacks. Weighing in at 50 tonnes each, these structures provide a remotely operated interface for pressure and flow between these wells and the Thylacine platform. We have already placed Christmas trees on both Geographe wells, and we have the rest of the trees in Australia in readiness to install on the Thylacine wells once they are completed. We did experience downtime offshore due to a loss of more in-line tension event, however, this is behind us, and we expect to make good progress on the drilling front during the approaching summer months. We are also monitoring the COVID-19 situation and are working with governments and regulators to minimize impacts on our program. Our 6-well offshore development program commenced in May 2021, immediately following the successful discovery of Artisan. From a risk and complexity perspective, our extended reach well at Geographe-4 and horizontal well at Geographe-5 were Beach's most complex wells. We have successfully delivered both of these and both are in line with our pre-drill expectations. We are in the process of completing these as future producers, after which we will move the rig south to Thylacine to commence drilling the less complex for Thylacine development well program. Now turning to the Perth Basin. Let's talk about the Perth Basin strategy and business, where in 2019, we aligned our interest 50-50 with Mitsui to drive basin commercialization. From the first time in the company's history, we are moving towards global LNG sales from the second half of 2023. There's a combined gross 2P reserves of 200 million barrels of oil equivalent, including 1.2 trillion cubic feet of gas across our Perth Basin acreage, 77% of which is undeveloped. As such, the basin represents a truly transformational opportunity for Beach to create a material gas hub in the Midwest region of Western Australia. By the second half of 2023, the Beach Mitsui joint venture will have 3 gas plants in the basin with a total installed capacity of approximately 290 terajoules a day gross. The Mitsui operated Xyris facility and the Beach-operated Beharra Springs facility are currently supplying the West Australian domestic gas market and will continue to do so at the current combined capacity of 40 terajoules a day. The game changer here really is Waitsia, and it is an exciting project for the joint venture, the state of Western Australia and the regional economy. It is the first gas project of significance in WA in over a decade. And we'll be the first greenfield third-party project to supply gas to the North West Shelf for liquefaction. The joint venture has all the agreements in place to transport, liquefy and export gas from the Perth Basin. As you heard earlier, a heads of agreement has been signed with BP for all of Beach's 3.75 million tonnes of LNG from the second half of 2023. The joint venture is also planning to recommence exploration and appraisal activities in FY '23 with a view to provide optionality for gas commercialization. You will hear later from Sam about the prospectivity of the Perth Basin and the Kingia gas play. Potential exploration and appraisal success in the basin will create additional gas-to-market opportunities, meeting the needs of a tightening domestic gas market and the potential to support opportunities for new demand. The capacity across 3 gas processing facilities and potential for debottlenecking and expansion will place Beach and Mitsui in an enviable position by FY '24. The Waitsia gas field is located 18 kilometers east, southeast of Dongara, about 350 kilometers north of Perth within the L1 and L2 permit operated by Mitsui in a 50-50 joint venture with Beach. The gas field was discovered through the drilling of Senecio-3 in September 2014 and comprises the Kingia sandstone and the Highcliff sandstone pools. Appraisal was undertaken in 2015 with the successful drilling of Waitsia-1 and Waitsia-2. The field began producing natural gas in August of 2016 following the completion of the Waitsia Stage 1 project. That project connected circa 11 terajoules a day of deliverability from the Waitsia-1 and Senecio-3 wells to a refurbished Xyris production facility with export via the Parmelia gas pipeline. Further appraisal was undertaken in 2017 with Waitsia-3 and Waitsia-4. The Waitsia discovery remains Australia's largest onshore conventional gas find in 40 years, assessed on a 2P proven and probable reserves basis. The most recent expansion project was completed at Xyris in August 2020. The project connected another well, Waitsia-2 and increased the Xyris plant processing capacity to be on 29 TJs a day. Importantly, we connect the Xyris plant to the Dampier to Bunbury Natural Gas Pipeline with the connection size to accommodate future volumes from the Waitsia Stage 2 project. The Waitsia Stage 2 project is the next phase of field development and will provide an order of magnitude higher processing capacity to commercialize the Waitsia gas field. When complete, the project will consist of circa 250 terajoules a day gas plant with a 25-year design life with gas gathering, hubs and flow lines, liquids handling, compression and condensate load at facilities. Infrastructure will be installed to accommodate future expansion and compression to extend the field life as it matures. The Stage 2 project will involve the drilling and completion of an initial 5 conventional development wells. The system will allow for production from the existing Xyris gas facility to continue in addition to the new Waitsia gas plant. Gas will be supplied into the Dampier to Bunbury Natural Gas Pipeline, which will be processed into LNG at North West Shelf on a tolling basis. This will occur over a 5-year period commencing the second half of 2023, after which gas will be supplied directly into the domestic gas market. The Waitsia gas field is a world-class low-cost onshore conventional hydrocarbon resource of 810 petajoules of gas on a gross basis. Over the past 3 years, we have conducted a disciplined development evaluation through a basis of design and front-end engineering design in the form of a design competition. This matured the opportunity to enable the Waitsia joint venture to take a final investment decision earlier this year. Construction has commenced on site, and the program is on schedule. From a marketing perspective, we have signed a heads of agreement with BP for the purchase of Beach's 3.75 million tonnes of LNG from 2023 to 2028. With the domestic market expected to tighten further from the mid-2020s, the project is well placed to supply the West Australian market versus the current export window. Also, with a total installed cost of between $700 million and $800 million gross, the project represents attractive value with rights of return in excess of 20%. I'd like to emphasize that the Waitsia Stage 2 project is an upstream project. And as such, has a much lower cost and schedule risk profile to traditional LNG developments, which have complex liquefaction tank and jet infrastructure components. Waitsia gas will come off to very same loading arms in the North West Shelf that has been supplying international markets for the past 30 years. This simpler plan design provides the first line of defense against delivery risk and also underpins the low technical cost of the development. The second line of risk mitigation is through our contracting strategy. Over 70% of the total project costs are fixed, with over half of the capital spend for the project being executed under a lump sum turnkey EPC contract for the gas plant. This has been awarded to Clough, a reputable engineering and constructor who have been on the Waitsia journey for several years. As per standard EPC contracts, we have liquidated damages for both schedule delay and plant underperformance. Clough are performing well with construction activities underway and progressing to plan. Another line of risk mitigation in this era of COVID-19 is through supply chain strategies and local content. It is important to remember that the project was front-end designed, bid, negotiated and awarded during the heart of the pandemic in Australia. As such, extra attention was afforded to supply chain strategies to minimize these impacts and leverage Australian, Western Australian and regional content. Let's now turn our activities to the Taranaki Basin. Our existing assets at Kupe comprised of 3 production wells and unmanned offshore wellhead platform in 35 meters of water, and the 30-kilometer subsea pipeline that brings raw, natural gas and liquids from the platform to shore where it is processed at the onshore production station. Once processed, a 12-kilometer sales gas pipeline takes natural gas from the production station to Kapuni where it is injected into the North Island transmission network. Condensate is transported via road and shipped internationally, while LPG is transported via road for the local market. In line 2019, the Kupe joint venture consisting of Beach's operator, Genesis Energy and New Zealand Oil & Gas committed to investing in compression to extend plateau production of 77 terajoules a day until mid-FY '24. This project is now complete and represents our first material production uplift from our project portfolio. Kupe is a critical part of New Zealand's energy infrastructure. Our operated Kupe project supplies 15% of New Zealand's annual natural gas demand and 50% of New Zealand's LPG demand. With 27 million barrels of oil equivalent, net 2P reserves in the Taranaki Basin, including 113 petajoules of sales gas. Our strategy is to maintain plateau production. I'm pleased to say that the Kupe inlet compression project has achieved first gas ahead of plan. This is a milestone that signifies the completion of all mechanical construction, pre-commissioning and commissioning activities, to enable the startup of the newly installed compressor on Kupe gas. We will be ramping up to 77 terajoules a day in the coming weeks. We are very proud of this achievement as we have delivered the project safely, on budget and despite COVID-19 impacts and restrictions. It is a true testament of our values here at Beach. We are, of course, reviewing opportunities to extend this plateau beyond FY '24, and plan to commence work on a potential Kupe East development well, which could lead us drilling in FY '23 subject to approvals. This well could be drilled from the existing platform and drain incremental 2P reserves in the Eastern combination of the field. The team is also looking at other exploration opportunities for tieback to the existing Kupe infrastructure. Before I hand over to Sam Algar, I would like to provide an update on our development activities in the Bass Basin. The Bass Basin is located offshore between the southern tip of Victoria and the northern margin of Tasmania in the shallow waters of the Bass Strait. The original BassGas project sanctioned in 2001 and delivered in 2004 was based on the development of the Yolla field discovered back in 1985. Current assets include 4 production wells connected to the Yolla-A offshore platform in 80 meters of water. Gas and liquids are transported via 147-kilometer subsea pipeline and a 32-kilometer onshore pipeline to a processing plant near Lang Lang, Victoria, with a capacity of 70 terajoules a day plus LPG and condensate. Beach has conducted concept select engineering in FY '21 to investigate opportunities to extend the life of the infrastructure, and has since entered FEED to provide further definition. The current base case concept consists of 2 Christmas trees, 1 subsea distribution unit and a new 38-kilometer umbilical to the Yolla platform. Later this year, Beach will undertake a 3D seismic survey to improve the imaging of the Trefoil field. Processing in early 2022 will help inform the final design and decision support package for the development with regards to future tieback options for our White Ibis and Bass discoveries. The strategy for the Bass Basin is to increase the utilization of the Lang Lang facility and extend the life of the existing offshore infrastructure. Although BassGas volumes are contracted, a potential Trefoil development has exposure to a tightening East Coast gas market, hence, work is underway to further define the business case. Neither the Trefoil development or the planned in wellbore opportunities in FY '22 to improve on the current production performance are included in our BassGas. We are doing work to inform our development plans and dimension the upside potential through the reprocessing of existing seismic as well as conducting new 3D seismic survey over the Trefoil later this year. In parallel, we are conducting front-end engineering design for the subsea pipelines and brownfield modification works. This includes detailed well engineering, rig selection and contracting activities and planning for long lead item procurement. This work will inform our final investment decision for Trefoil in the first half of FY '23. If sanctioned, this $500 million to $600 million growth project is anticipating first gas in the second half of FY '25. With that, I would like to hand over to Sam Algar.

Good morning, everyone. My name is Sam Algar, and I joined Beach this February as the Group Executive of Exploration and Subsurface. What drew me to Beach was the range of assets across multiple basins, all with access to existing infrastructure. What I've seen since I arrived has excited me even more. The portfolio of exploration and development opportunities is one of the highest value ones I've worked on in my career. My team and I are working closely with Thomas, Ian and Lee's teams to design a long-term value-accretive activity program. Upfront, I want to make it clear that our choice of which opportunities to pursue are very much value, not volume-based decisions, though they will, obviously, often also increase our production. Ian and Thomas have already covered some of the highlights of our production and development business, including the recent Geographe development drilling program. So my focus will be on talking you through the upside of our assets that is largely attained through exploration and appraisal. Starting with Otway where our objective is to provide the lowest cost feedstock gas to keep the gas plant full. Historically, drilling within our Otway Basin acreage has had a 100% drilling success rate due to the strong correlation of seismic amplitude with the presence of gas. In addition to our recent successes in Enterprise and Artisan, we have several other prospects with similar seismic response consistent with the presence of gas. Shown in the seismic attitude extraction map on the right-hand side of this slide, there are 5 prospects in the broader Geographe, Artisan fairway. We're working out the resource potential as we speak. But for reference, you can see the size of these amplitudes in relation to the estimated ultimate recoverable volumes for the Geographe and Artisan fields. You should also bear in mind that each feature can have multiple reservoirs, not all of which are shown in this image. We're currently putting together a plan for exploration activities for these prospects. And importantly, along with the discovered Artisan and La Bella resources, these prospects could share development infrastructure. This, we'll see Beach supplying the lowest unit technical cost gas to the onshore gas plants, keeping their Otway gas plant on plateau production and maximizing value. This work is ongoing. However, this would likely see us return to drilling in FY '23 or FY '24. Moving now to the nearshore part of the Otway Basin. Our recent Enterprise discovery was drilled from onshore to offshore. This approach minimizes the need for new infrastructure and completely negates the need for unsightly and costly offshore infrastructure. As Thomas has highlighted, we're progressing our plans to tie this well into the Otway gas plant and Enterprise is expected to be one of the highest returning projects in our portfolio. The other good news is that Enterprise has opened up a fairway of potentially similar nearshore opportunities, which can be drilled from onshore. On the currently available seismic data, we can see 3 similar prospects and the seismic amplitude extraction on the image on the bottom right shows 2 of these, the Archer and Rayville prospects. Whilst we do see amplitudes consistent with gas, we do not have full 3D seismic coverage of these and other leads. And so we're considering acquiring additional 3D seismic prior to drilling. Depending on the timing of the seismic, we hope to be drilling these exploration prospects in FY '24 or '25, though it could come earlier if we elect to drill without further seismic. Importantly, at least one of these prospects could be drilled from the onshore Enterprise drill site. If successful, it could rapidly be tied into the Otway gas plant. Moving now to another basin, which has significant potential for material value growth, the Perth Basin. The recent discoveries of Beharra Springs Deep, West Erregulla-2 and now, Lockyer Deep have highlighted the very significant potential of the Kingia play. It's our opinion that the Beach Mitsui 50-50 joint venture has the dominant position in the Kingia play. As such, in the map, we have defined 9 prospects on 3D seismic and 5 leads on 2D seismic. We expect these 14 prospects and leads to have similar potential to the existing discoveries, noting that the combined gross 2P reserve of the Waitsia and Beharra Springs field to 1,166 PJs. Beach and Mitsui are prioritizing drilling locations for an FY '23 drilling campaign. The number and objectives of these wells are still being discussed. But at this stage, we're looking at initially drilling between 3 and 6 wells with 2 key objectives: firstly, to develop Beharra Springs through debottlenecking and further expansion; and secondly, to explore and appraise material resources on the scale of multi-hundred Bcf. On the right-hand side of this slide is a seismic line going for Waitsia through exploration prospects, Gynatrix and Cable, to Beharra Springs and on to another large exploration prospect, Floreat. It is likely that our FY '23 drilling program will include a new well or wells in Beharra Springs and near-field exploration would also inform the scale of potential Beharra Springs expansion. On this slide, we see another seismic line, showing some of the other exploration potential around Beharra Springs and also the structures of Trigg and Cottesloe. Our interpretation of Trigg is that it is updip from the West Erregulla discovery. As you can see from the map, the scale of this feature is potentially very material. As such, Trigg is like to be one of the wells we drill in FY '23. Moving now to the Western Flank, where we're shifting from a phase of development to one of exploration, appraisal and development. We operate all of the Western Flank infrastructure with 27 oil fields producing high-quality crude that typically demands a premium to Brent as well as 4 gas fields that keep our Middleton gas plant producing at a plateau rate of approximately 30 TJs per day. Our asset strategy is to maximize value from our existing fields through efficient operations and a relatively small amount of in-field drilling complemented by exploration. This will convert the remaining undeveloped reserves to developed and producing reserves. The exploration will initially be likely to be undertaken in the acreage adjacent to our existing infrastructure with no exploration success factored into our FY '22 guidance. The Western Flank is unusual relative to the other assets in our portfolio and, indeed, many of the other basins in the world. So it's worth a quick introduction before I describe our fields and our exploration potential. The basin has been producing for around 20 years from 3 reservoirs, the Namur, McKinlay, Birkhead. The majority of early success was in simple structures containing the high deliverability Namur reservoir with a material pickup around 10 years ago with the discovery of the key fields that are still producing to this day. The McKinlay was, for many years, overlooked lower-quality reservoir sitting immediately above the Namur often in the same structures. And Beach realized that the oil in McKinlay could be accessed through horizontal drilling. As such, horizontal drilling has been responsible for the very material increase in production over the past 4 years. The Birkhead sits typically 230 meters below the Namur and is present in many of the same structural traps at the Namur and McKinlay. But the largest Birkhead fields discovered so far are, however, being in stratigraphic traps, mostly in the northern part of the Western Flank. What makes the Western Flank so unusual, though, is how flat the structures are. The distance from the top of the oil to the base of the oil is usually less than 10 meters versus 100 meters or more in most other structures in our portfolio and indeed in much of the rest of the world. An example of this is shown in the seismic line through the Bauer field on the bottom right-hand side of this slide. This flat nature means that the fields are hard to resolve with seismic, and the seismic amplitude work that has made us so successful in the Otway is just not possible here. This, therefore, makes interpretation of the structural form of the discoveries and, thereby, their resource size and reserves very challenging. As an example of this, the Bauer field when discovered was thought from the seismic available at the time to be only 1 million barrels in size. Subsequently, drilling has shown that the field is an estimated ultimate recovery of 40 million barrels, 30 million barrels of which has been produced already, and the remaining 10% will be produced in the coming years, mostly from the existing wells. The map on the right-hand side shows our operated oil and gas infrastructure in the Western Flank. In the 27 oil fields, we have 185 wells producing, of which 115 are on some level of support, typically either beam pump or ESP. Majority of the fields are fully appraised and producing under natural reservoir decline following extensive development drilling in FY '20 and FY '21. In Q2 FY '22, we're looking to reduce the rate of production decline somewhat by drilling 5 development wells. These wells will be in the Kalladeina, Balgowan, Spitfire, and Growler fields on the map. In addition, we are looking at opportunities to recomplete other reservoirs in existing wells. For example, produce oil from the Birkhead reservoir in well originally producing oil from the Namur. The level of performance we get from these activities, combined with the performance from the 185 existing wells, will determine the exact rate of production. Moving now to the Martlet field. In the northern part of the Western Flank, along with the Growler and Spitfire fields, were all previously operated by Senex. We feel there is potential for material upside to Martlet as it only has 2 wells which might not be accessing all of the fields oil. As such, we're planning up to 3 vertical wells to appraise the field. If successful, these wells will help us size appropriate facilities to produce the additional oil from FY '23 onwards. Success at Martlet could enable us to book additional reserves, but it's not assumed in the base production. The Western Flank focus for Beach over the past few years has been on development of the existing discoveries. And as a result, there really hasn't been any material exploration in Western Flank at all for the past 5 years. Now we're keen to get back to exploration in the Western Flank as it should have a lot of high potential, high-value potential remaining. So far, we've matured 24 exploration prospects, which are located in red in the map on the right-hand side. In the second half of FY '22, Beach is planning to drill up to 15 exploration wells. We'll initially focus on the lower-risk proven reservoirs of the Namur and McKinlay in structures that are adjacent to our existing fields. This keeps geological risk lower and enables us to cost effectively tie in any discoveries in time to impact FY '23 production. These are relatively cheap wells costing AUD 1.2 million to AUD 1.5 million each. The total campaign cost of $21 million is similar to the gross cost of a single well in the Perth Basin or half of an offshore Otway well. These low drilling costs, combined with low development costs due to the proximity to our operated infrastructure and our very low operating costs, mean the discovery is larger than 100,000 barrels of commercial. Indeed, many of our exploration prospects, if successful, would have internal rates of return of more than 100%. And we expect to begin exploration drilling early in Q3 of FY '22. And with success, we'll move to appraisal and development later in FY '22 and early FY '23. We're looking to bring discoveries on as early as possible. And with success, we will then continue to drill some of the other prospects in the portfolio, particularly those have been derisked by the discoveries that prove new oil migration routes or structural trends. Moving now to Western Flank Gas. We've already commenced a 4-well exploration campaign there. The historical success here has been around 50%. And I'm pleased to say that of the 3 wells we've drilled so far, we've already made 2 discoveries at Rosebay and Lowry South. These are new gas pools not connected to the existing gas fields and will be tied in later in Q2 FY '22 and put on production to determine their full potential. We're also looking at additional gas well locations in the immediate vicinity of these wells, but also further south. Their drilling will be timed to keep the Middleton gas plant at plateau production. The Cooper Basin joint venture is operated by Santos and represents a very material contribution to our production and reserves. There are around 190 fields producing through the Moomba gas processing facility. And our focus is on ensuring continued value creation from this asset through the safe and efficient production from existing fields and drilling of additional development and, to a lesser extent, exploration wells. Shown in the map here are the results of the FY '21 drilling campaign with 84% of the wells being suspended and completed as future producers, predominantly gas, but also some oil wells. In FY '22, we're doubling the level of activity to around 90 wells for the year and have already got off to a good start with some very encouraging gas results in Durham Downs North and a number of other fields. We are leveraging our experience in drilling horizontal oil wells in the McKinlay to support Santos in their 6-well drilling campaign in the McKinlay oil field. The program is over halfway through and results are in line with or better than our predrill expectations. So in summary, I hope I've given you a taste of what has made me so excited about the upside potential of the assets that Beach has. And I look forward to bringing you updates on the progress of this activity in the near and medium term. With that, I'll hand back over to Matt. Thank you.

And with that, we're nearing the end of our prerecorded session. We've given you a significant download of the Beach business, our strategy and highlighted our confidence in meeting our growth targets. Before I hand back to a live portion of today, I wanted to quickly reiterate the key takeaways from the presentation. One, just taking account of our committed growth projects, we expect to deliver an FY '24 production target of approximately 28 million barrels of oil equivalent. This represents a CAGR of around 13%. This target excludes exploration success and pre-FID projects with Enterprise being the only exception. We're pleased about the progress made to date, and we're looking forward to completing our growth execution phase, noting that the middle of FY '24 is only 2 years away. Two, our balance sheet is rock solid. With the company in a net cash position of around $50 million as at 31 August. Through the capital spend peak cycle over the next 2 years, we don't see our net gearing exceeding 10% based on our current outlook. Three, we've deliberately created a diverse gas business. By the end of 2023, we expect to have 8 gas plants producing from 5 basins. These plants will deliver gas to 4 markets, including focus on the short East Coast gas market and the global LNG market. Four, the breadth of that gas business not only provides downside protection, but it also creates a stream of material, stable and predictable cash flow. From FY '24, we expect to be in a position of material free cash flow. That creates multiple forward capital management alternatives for the company. Five, last, but certainly not the least, we're focused on being a sustainable company that can support the energy transition. We have a net zero ambition by 2050. We're already delivering on emissions reductions in our operated assets. In addition, the Moomba CCS project provides us with an opportunity to make a material step towards the net zero target. With that, I'll hand back now to the operator because we look forward to the live Q&A session. Thank you.

[Operator Instructions] Your first question comes from Daniel Levy with Citi.

Congratulations on the great Strategy Day. I just wanted to get a bit more color on the structure of that LNG HOA that you signed with BP. Perhaps, a little bit of information on the linkage to the 2 benchmarks and the downside protection.

Yes. Thanks, Daniel, and good morning, everyone. Look, obviously, there are confidential terms in relation to the LNG heads of agreement with BP, so I can't share too much more than what we've already shared. I mean importantly, as we said, we've been engaging with around 20 customers. We had genuine term sheets in from 14 customers. So it was quite a hotly contested profile that we went through. We do have, as you've said, linkage to Brent and to JKM, which is great. We've got some downside protection. Importantly, we're not capped on the upside, so it's not an S curve. We're really pleased with the outcome, but obviously, all the key Ts and Cs are confidential, so I can't really share much more than that with you.

Fair enough. Can't blame me for trying. And then just a couple of questions on the Perth Basin. First, I just wanted some clarity. You said you have 14 prospects that have -- and they have similar potential to existing discoveries. I just wanted to check if you mean that kind of, as a whole, they have a similar potential to the 1.1 Tcf growth you guys already have? Or you're saying that each prospect is potentially a Tcf prospect?

Yes, sure. We should have said at the outset that if we were doing this live in a room, we'd have a panel here with all the execs, but all of the presenters are in the room, and I'm keen for them to get a chance to answer questions and speak as well. So I might actually bring Sam up to address the future of the Perth Basin from our perspective.

Yes. Thanks, Matt, and thanks for the question. I mean, I think first off, we've been very clear, Perth Basin is a really exciting basin. I think the recent discoveries at Lockyer Deep. And obviously, West Erregulla and our discoveries in Beharra and Waitsia set the scene for what is a really exciting basin. As to the exact resource sizes, time will tell. We're optimistic, but at the same time, we understand there's quite a lot of uncertainty. The column height is one question, which creates quite a wide range of uncertainty in the resource size as does the reservoir thickness. So until we've got the drill bit in the ground and got some results, I think that's when we'll come back to you with some better ideas. But I think from the map that we've shown in the presentation, we've got 14 prospects, 9 of which are delineated on 3D seismic. So it's a really exciting time for us.

Sorry to kind of press the point. I'm just curious on that. So the bullet points of individual prospects have similar potential to existing discoveries. So is my read through there that some of these prospects are potentially Tcf discoveries? I'm not supposed to think of the whole thing as potentially Tcf?

Correct. Yes. So I think what we're trying to -- the analogy we're trying to show here is if you just look at the areas of those, then they certainly have those potential. But as I said earlier. The exact results will be dependent on the outcome of the drill bit, and we look forward to that.

Perfect. And then just finally on Perth Basin, just interested on your thoughts of where kind of another Tcf+ discovery would go. Do you think there's potential to keep backfilling a rapidly declining North West Shelf? Or would you shift focus to creating your own demand through pet chem like others in the basin, or potentially into the DomGas market if you think it has the bandwidth by that point?

It's a good question. I think my answer would be, I think you've answered the question for me, so thank you. I'd say all of the above, frankly. So obviously, there are restrictions on the amount of gas we can export at the moment out of the Perth Basin. That was predominantly because the state government was concerned about an East Coast gas situation being created on the West. So we're hopeful, not guaranteed, but hopeful that with more discoveries in the West and with more gas coming to shore, from the offshore developments, then that may loosen up, but we can't promise that. In addition, we do see the market in Perth starting to tighten up a more domestic opportunity to be created. I think the other point is we've got some time here. So we've got a few years to able to get ready from a market perspective. And if that means creating new market or expansion markets, including petrochem, we've got the capacity to do that.

Your next question comes from James Redfern with Bank of America.

Thanks for the detail today in the presentation. Just wondering if you could please provide some guidance around how we should think about the production rate from the Geographe-4 and -5 wells and Enterprise-1 just given the uplift in the production from the Otway. And then second question is just maybe an update on the Genesis sale process for their 50% stake in Kupe and whether that's still ongoing. Or is that being terminated?

Yes. I might start on the latter question first, James. So thanks for the questions. Yes, our understanding is that Genesis have terminated their process. I think they made a public statement on that a number of weeks back. And I might actually, again, give Thomas a chance to speak and let him give you some background to the Otway and our program of refilling the Otway. Thomas?

Yes. Good morning, everyone, and thank you very much for the question. Clearly, as I articulated in the presentation, gas is due to come on stream mid-FY '22 from a Geographe program. As far as the contribution of the Geographe-4 and -5 wells is about 70 million barrels of oil equivalent. Of course, the Enterprise program is also progressing quite well. We are in FEED now. So that's due to actually come online in the second half of FY '23 coincident with the Thylacine program. So altogether, the 4.7 million barrels of oil equivalent contribution from these 3 developments is due to hit the Otway gas plant in the second half of FY '23.

Your next question comes from Dale Koenders with Barrenjoey.

You've pointed to the EV per boe discount multiple relative to peers and gearing not exceeding 10% in the coming years with potential to utilize in FY '24. I guess on this question, why do you need to wait that long? Is this lazy balance sheet management? Are you looking at inorganic growth, probably underestimating execution or financing risk? And if your answer to all of those is a no, why not use your balance sheet to buy your own stock back if value is compelling?

Yes. It's a really good question, Dale. I think from our perspective, as we said a number of times during the presentation, we are keen to maintain a strong balance sheet during our peak CapEx spend. And obviously, this year, and, to some extent, next year is our peak of capital spend. Now we recognize we're in the oil and gas business. While we do everything we possibly can to mitigate risk, it doesn't mean we're without risk. So we do want to get through some of the risk profile of our current spend and our current programs. And then that leads us to a path of significant free cash flow, as we've said, from multiple plants and multiple basins. And that gives us a lot of optionality, frankly. It gives us optionality on reinvestment back into the business, optionality on M&A and optionality on capital management, including dividends and other elements that you've mentioned. So they're all open to us, but from our perspective, we think the right thing for at least the next 12 months or so is to keep the balance sheet in great shape while we go through our capital spend profile. That's the key.

Where is the risk in your mind? Is it around timing of certain projects moving forward? Or is it purely around exploration, potentially in an offshore Victoria environment, which is prone to cost escalation? Where do you see that risk?

Yes, it's a good point. In terms of trying to prioritize and categorize the risk, I think the Otway is probably the highest risk profile on our book at the moment given that we are offshore. You do face a fair amount of weather challenges out in the Otway, which we've been through this winter. But we are seeing it derisk at the moment. Obviously, we've got the Christmas trees landed for the current wells. We've got to tie them back and get them going. So there's always an element of risk in that. We think we've got the team to manage it well. We think we're well placed. And then on Waitsia, I see that as a much lower risk profile, frankly, it's onshore. We're using Clough in terms of our contractor who've been there and done it before. We've got a large amount of our capital, sort of 60% on that contract being a lump sum, turnkey. And then thereafter, we go into the North West Shelf existing facilities. So I do think, probably, if I was going to rank them, I'd say the Otway is the higher of the risk profile given it's in an offshore environment. We think we can manage it. We think we've got the team to manage it. Are we being conservative? Possibly, but we're comfortable with that.

Okay. And then just one other quick question on aspirations to be net zero by 2050. It's obviously another commitment to be net zero by 2050. When do you think you'll be in a position to better articulate the pathway and sort of longer term beyond your short-term targets? And do you think it's going to be a large part of abatement? Or what technology do you think you will require to get there?

Yes. Look, it's a really good question, Dale. I think we're really well placed frankly as a company. We came out at 2020 and announced the 25 by 25 program, which was a 25% reduction in our emissions on our operated assets by 2025. We're already halfway there. So we've instigated a number of projects across all the gas plants to achieve that already. When we took the decision on FID for Waitsia, we agreed to offset all of our reservoir emissions. So that's 60% of the emissions from that project. We're looking at how we offset the other 40% from the project as well. And as we've talked about, a big step change for us, obviously, is the potential for CCS at Moomba, which we're through FEED. So we're getting FID ready along with Santos on that project. If you add all of those up, then you'll see a substantial step change in our emissions. And as they progress, we'll continue to inform the market as we progress through the gates.

Your next question comes from Saul Kavonic with Credit Suisse.

A couple of quick questions, if I may. First of all, just coming back to the Perth Basin and the exploration [indiscernible] there. Sam, can you give us an indication of when could we potentially see the first results which could lead to a resource increase out of the Perth Basin?

Okay. I'll let Sam jump in for that one. Thanks, Saul.

Yes. Saul, so we're going through with our joint venture partner, Mitsui and planning the exploration -- FY '23 exploration program at the moment. So at the moment, we're looking like we, hopefully, will start drilling in the second half of the calendar year in FY -- in calendar year '22. So that's the first half of the FY '22 -- '23, sorry. And the results of that, obviously, will be towards the end of the calendar year for the first well. As I said in the presentation, we're looking at between 3 and 6 wells. So that information will flow through in time. The exact timing will depend upon the progress we make with the development drilling in Waitsia beforehand. As Thomas highlighted, we have a number of development wells there and we're looking to follow on that program with the exploration afterwards.

Right. Are you able to give us -- it's still -- we don't over the full cost structure here. I appreciate this commercial sensitivity around the elements, but could you give us an indication perhaps of what the, for example, the FOB breakeven of rates is LNG on a boat?

Matt, do you want to take that?

Yes, we -- thanks, Saul. It's a good question. I understand why you're asking it, but we are being a bit careful around some of those numbers, of course, given that we've got third parties that we engage with, both in terms of sales and other transactions. What I think, I know that you note -- yesterday, I think you were spotting it, it is a highly, highly competitive project because you're looking at onshore facilities, you're looking at high-deliverability wells, you are backhauling on a backhaul tariff up the Dampier to Bunbury pipeline. You're then going through the North West Shelf infrastructure, which is one that's truly tried and tested, and at a rate that we're very comfortable with. So from our perspective, we are highly competitive. Landed on a boat at FOB, I think you were spotting that in your note yesterday to the market, which I support. So from our perspective, we think we're incredibly well placed as a project. It's a high-returning project.

Great. Last question for me is just on the FY '24 guidance, 28 million barrels. That's about 7 million barrels less than the prior FY '24 guidance you gave. So 7 million-barrel drop, is that all Western Flank? Or is there anything else that has changed in that?

Yes, again, good question. Look, I've got to be a bit careful referring back to any previous investor days because we have removed that -- those previous numbers. But what I can say to you is, A, they're not directly comparable because we've removed any exploration upside from the Western Flank; and we've removed any non-FID projects other than enterprise. I think on our numbers, our thinking that's changed between a year ago and now would be that about 90% of the volumes that are coming out in FY '24 are Western Flank related. So about 90% of it is Western Flank.

Your next question comes from Daniel Butcher with CLSA.

Just start with one quick one on Moomba CCS. I know you sort of talked about maybe a little bit less -- promotionally in your part. I'm just sort of curious what risks you see around Moomba in terms of technical risks and regulatory risks remaining and what your view of the economics is.

Great. I might let Brett join us for some of that as well. So appreciate the question, Daniel. Look, one of the reasons we're being a little bit more tempered than Santos is they are the operator. And we're very comfortable that they are the operator, and we're comfortable with them taking the lead in the market and with government and others. We are side-by-side supportive, but you will absolutely continue to hear Santos taking the front position, as they should, as the operator on the project. But we are very supportive. We put a lot of effort into our FEED program that we've got through, and, fundamentally, where FID really subject to terms. I might let Brett jump in at this point.

Thanks, Matt. Good morning, everyone. Yes, on the technical risks, the process, although it hasn't been operated by Santos before, it's a pretty straightforward process. And over the past 4 or 5 months, I've been heading a technical team with recourse to external CCS expertise that's assisted us in going over what Santos had done. And we're quite confident that Santos is above the technical risk. From regulatory risks, Santos, and we've been working very closely with the clean energy regulator, and at the moment, the CER has a draft application that it's reviewing on Santos' behalf. And the feedback that we've got to date is that it seems to be a solid application. So we're confident that should the CER and the minister approve the methodology, the project will be approved.

Okay. Great. And just a second one, if I can, just back to the LNG contract. I take your point, you don't like to give too much away. But just in very broad terms, if the JKM portion was, say, $8 DS in Japan, would you be taking about $3 off in total to get back to the feel that's [ weightier ]?

It was worth a shot, Daniel, to try and get more information from me. But yes, I think I've shared a lot with the market, and we've shared a lot with the market today and yesterday in relation to that contract and the sales terms. And literally, we've shared as much as we can, unfortunately. As I said, we're really comfortable with where we've landed. We think we did the marketing at the right time in the cycle and post the previous downturn in the market from, frankly, what we've seen in the last 12 or 18 months. So from our perspective, the timing is right, highly competitive, 20 customers engaged, 14 giving us full-term sheets and a number of others throwing spaghetti at the wall as well. And I want to highlight as well, BP is a fantastic customer. They're first-class, obviously, from a balance sheet perspective; first class from an industry perspective. And we look at their shipping business in Asia Pac, and we think that's the ideal linkage for us. So from an offtake perspective, we think they're pretty close to the top of the tree. And obviously, they understand North West Shelf incredibly well. So we're really pleased with the outcome, but I can't delve into more details. I think we've given you a lot already.

Okay. I'm sorry to try again, but I'll leave it there. And just maybe finally, I mean, unit sales -- after that gearing. It's not a question, just when follow-up. Post the next couple of years of CapEx, what would you think your ideal gearing range is then?

Yes. It's a good question, Daniel. We tend not to think -- and I think we've said this for a number of years, we tend not to think of the business as what's an ideal gearing position. So for example, if we were setting net cash as we would expect to be in a couple of years' time, we're not going to go and make an investment just to get our gearing up to 30% or 40% to a target range. We're not going to do that. We look at all the key metrics of the business. We look at all the key metrics of any M&A, any reinvestment. We are incredibly disciplined as a company in terms of what we spend our money on and how we reinvest and what type of returns we expect. So for us, the key driver is not what the net gearing is. A key driver is order metrics and just that. But look, we're fortunate. We're going to be in a situation, as we've said many times over the course of the call, where we have really stable business. We've got a lot of cash flow coming in from 8 gas plants across Australia and New Zealand. And we'll be tearing through that debt in a hurry from that business, and then we'll have a lot of optionality ahead of us. We don't have to make those decisions today, but within the next 2 years, we've got some decisions to make, and we'll inform the market as we get through the gates of those decisions.

Your next question comes from Nik Burns with Jarden Australia.

Thanks, Matt. And first of all, a big congratulations to the team for pulling together today's presentation. I know firsthand how much effort goes into these things, so well done. Just first of all, on M&A. Beach has a positive track record in value accretion in M&A. We've seen some big announcements amongst your peers in recent months. Some would say it's a signal that ESG pressures are driving consolidation. Just interested in your view on this. And are you feeling any pressure to look at M&A to gain scale in the face of these rising ESG pressures?

Yes. Thanks, Nik, and it's a good question. Look, I won't comment on other people's transactions. That's, obviously, not appropriate, but I do understand that a number of them were done for scale. Look, from our perspective, we won't -- again, we won't go and do a transaction just for scale. It will always be about value is #1, and we have multiple metrics that we screen any opportunity on. Do we feel the need that we have to rescale? No, we don't. We felt a need, as you know, in 2016, '17, that we needed to basically recast the company, move out of a single-basin focus, end up with multiple plants and multiple jurisdictions where we could reinvest. We've done that. So we don't feel any pressure point at the moment to go and do M&A and certainly not from a scale perspective. It's just not the way we're wired, frankly.

Got it. On oil markets, looking pretty favorable at the moment. I'm just wondering, is that a bit of a driver behind your decision to drill 15 Western Flank oil exploration wells in the second half of this year? And how should we think about your exploration program medium term? And is there any indication you can give around the type of -- or your unrisked success volumes you're targeting from those 15 wells?

Sure. Thanks, Nik. I'll let Sam come in and talk about the Western Flank oil exploration program. In relation to oil price, no, that had no influence whatsoever in terms of our decision-making. I mean, as we know, the Western Flank is a low-cost place to do business and margins are very high from our discoveries there. So economic cutoffs are incredibly low in terms of our hurdles. So for us, regardless really of what the oil price was going to be, we expect it to be back in exploration territory on the Western Flank. As people know, we've been focused on production. We've been focused on development, and now is the time to turn back to exploration in the Western Flank. So no, oil price has not influenced that decision at all, frankly. But I might let Sam talk a little bit about the plans.

Yes. Thanks for the question. As you would expect, obviously, we're going to be a bit coy on talking about resource estimates for the Western Flank. As I've highlighted, it's a tough area to estimate based on the seismic, and so the drill bit, again, will be the thing we'll be relying upon for the volumes. I think the key thing, as Matt's highlighted, is the incredibly high value of these opportunities. And we've also got a rather large number of them, so having matured 24 of them already. And so irrespective of the volume found, we're still -- we're expecting to make some good money out of these. As far as the success rate is concerned, historically, I think it's about a 1-in-3 success rate here. So with 15 wells, 5 discoveries would be a good outcome for us. And yes, we look forward to turning the drill bit and finding what we get.

That's great. Look, I might just follow-on on that. I think your focus for your exploration drilling in the Western Flank primarily on the McKinlay. Obviously, the recent Senex acquisition, XPO-104101, is primarily Birkhead focused. Is there any plans to look at exploration drilling in that acreage and focusing on that reservoir?

Yes, that's a good question, and we do certainly see a lot of upside in that acreage. And as we've noted, we're also doing some development drilling in the ground or in Spitfire fields where we see some upside and also appraisal and development drilling in the Martlet field where we see some upside there. The Martlet field's in Windimurra, and we do have a number of prospects in that area. At this point in time, we're stepping into the exploration relatively slowly and just focusing on the Windimurra adjacent to our existing facilities. But yes, we do have a number of very interesting prospects in the Birkhead, and we're pursuing those. We do see most of them to be at slightly higher risk than the prospects we're pursuing initially. So we'll step into those gradually as we get new information adjacent, initially, probably to the Martlet field and then stepping further out to the north. So as I said, the key thing with us is we're focused on value, and we are making sure that we learn from each prospect before we jump into other ones, which may be influenced by the results of those initial prospects.

Your next question comes from Gordon Ramsay with RBC.

Okay. Just a quick question on the Perth Basin drilling program. Trig, to me, looks like an extension of South Erregulla. So you're going to wait to see South Erregulla get drilled to decide what you do with the Trig prospect?

Gordon, good to hear from you. I might say again just let Sam talk a little bit about our thoughts on the Perth Basin.

I think if there's one thing I'm learning from these questions is you're all really excited about exploration, so I'm really pleased to see that. Yes. No, I mean, Trig, we think, is updip from West Erregulla and South Erregulla. So in many respects, irrespective of the results of South Erregulla, we're still very excited about Trig. But obviously, anytime there's new information which comes to light, we'll consider that and take that into account in our drilling decisions. The key thing is we think we're updip. We can see that in our 3D seismic, and that's very clear to us.

Okay. In terms of the LNG sales heads of agreement, Matt, when do you expect to move into a GSA on that?

Thanks, Gordon. So look, we expect probably in, I would say, by the first half of next calendar year, if not towards the end of this calendar year, will be the timing. Obviously, we have all the key terms that we need. It is a detailed heads of agreement. And as you know, this is tried and tested for LNG players, so we understand them well. So look, we're keen to get in and progress to the SPA. That will just be the teams working through all the details and lawyers' charging fees. So hopefully, we'll be done by early next year, if not, late this year.

And just one other question on this. What does up to 0.75 million tonnes per annum mean? Is there some flexibility in that contract?

There is...

Or headroom.

Yes. There is some flexibility around it, although, obviously, rates and offtake on an annualized basis are pretty well understood. But yes, there is some flex, but I wouldn't point that out as a major issue.

[Operator Instructions] Your next question comes from Mark Samter with MST.

A couple of questions, if I can. The first one, it looks, I think, pretty indisputable from, obviously, the operating cash flow you did last year and production guidance for this year, and it doesn't look like a recovery in production next year, but you're going to be free cash flow negative this year, next year. And I guess when we compare that back, to go back 2 years ago, you were forecasting $1.5 billion of free cash flow to U.S. will be -- from FY '21 to FY '23. And yet, when we look at the exit rate on that steady-state production level, you're 12 million barrels below the midpoint of that guidance. So I know there's a reference to material. I think it was the word used, free cash flow post FY '24. The number when used to give the annual numbers, it was FY '25, and that steady-state number was $1 billion a year. I'm keen to get a feel for -- there's a reasonable amount of fixed cost in this business and obviously amortized over lower production in this new steady state. Should we think about that free cash flow -- 12 million barrels of production, it was doing 25 million -- a $25 a barrel of free cash flow on the old? Should we think it's about $300 million a year lower? Or does that fixed cost mean that actual free cash flow is going to be lower still than in that steady state?

Thanks, Mark. There's a lot of numbers in that question, which, obviously, in answering the question, I'm not verifying those numbers. In terms of comparatives, as we've said, you really can't compare what we've announced through the course of this presentation with previous 5-year outlooks that we've talked about. We did obviously pull them from the market post the Western Flank reserves write-downs. But what we are saying clearly here is on the look-forward, and it's only 2-ish years away from FY '24, we're starting to see material free cash flow. Obviously, we have a large spend this year. We have a large spend next year. And then in FY '24, we're starting to see material free cash flow. From our perspective the key is -- the assumptions that we've got here is we've assumed we're just running down the 2P of Western Flank. We're not assuming any exploration success. So the big differentials on cash drivers, as I've said, for this scenario -- I'm not saying it will be the case, but for this scenario, is removing a lot of volume out of the Western Flank oil production. And as I said earlier, when we look at the numbers for FY '24 production, about 90% of that reduction, from what we thought previously, is due to the Western Flank. So I think that's the key guidance for you is we've assumed for this scenario that we're not getting an uplift from the drill bit for Western Flank. That obviously makes a big difference in terms of cash generation, but we are saying even without that, in FY '24, we're seeing material free cash flow.

Yes. And I guess can we just dig a bit more into that because I got quite a very wise man back to you called MacKay. Two years ago, he said that the August result -- he said -- I'm going to read it back, if that's okay. You said, "You can see that we're taking a conservative approach of forecasting, 37 million BOE by FY '25. In the interest of being prudent, our key assumptions in the low case are things that are virtually certain to post other upside. Even in the 43 million barrels of scenario, we can see outcomes are likely, given our previous track record of delivery, especially in Western Flank and Perth Basin. Prior case does not rely on material exploration success." And you also gave guidance around 2 or 3 years ago, the share of the forecast production that was going to come from each asset, and it didn't look like it had Western Flank growing enormously. So again, if we take the midpoint of that old 37 million to 43 million, 12 million barrels [ of BOE ] now, if you're saying it's 90% Western Flank, that's saying you expect Western Flank to have declined 10.8 million barrels versus the previous expectation, but I don't understand how you could have ever had the Western Flank doing 10.8 million midline more because it's not going to be 0. So can you tell us what 28 million barrels would have looked like on the previous assumptions?

Like, as I said, Mark, I'm not comparing back to the previous assumptions. I think one of the key elements in your question there is you were referring to FY '25 numbers, where we're now referring to FY '24 numbers, so they are different by nature from that perspective. They're also different by nature because, as we've said, we've assumed no exploration success here. So we're just assuming decline on the Western Flank, which we talked about 35% to 45% decline rates previously. So that is really the key issue for us. And look, when we said that we were confident in our previous numbers, that is because at the time, we're very confident in the Western Flank, and obviously, from our announcements in April, that was incorrect, and we've been very upfront about that, that the Western Flank outcome has been a surprise to us and a disappointing surprise to us. And when we look at FY '24 now compared to what we thought previously, as I said, 90% of that is Western Flank.

Okay. So sorry, just the first part of the answer to that question. Are you suggesting there could -- your expectation is growth FY '21 and FY '24? Or -- and that's why I shouldn't look at FY '25 versus FY '24? Or is that...

We're not giving guidance on FY '25 today, so I'll probably best stay away from that question.

Yes. Okay. I'm sure it's me being simple, but I'm still a bit confused how to reconcile just the quantum of decline and that can come at the Western Flank. Maybe care to shed some light there?

Sure. Yes. I was about to say, very, very happy, of course, to have further conversations with you today, along with Chris. I mean you've just put a lot of numbers in the room, which best, I think, dealt with off-line.

Your next question comes from Mark Wiseman with Macquarie.

Congrats on the Investor Day. I just had one for Morné on the refinancing of the debt facility. There's been quite a bit of discussion in the marketplace just around the banks' willingness to lend to oil and gas and their willingness to continue supporting existing customers. I was just wondering, can you provide a bit of color just on whether there's any sustainability-linked triggers in that debt facility or any other sort of new terms and conditions that you wouldn't have usually expected?

Thanks, Mark. You win the prize for the day for asking Morné a question. So thank you for that come. I'll let him come up and give an answer.

Good morning, and thanks for the question, Mark. I would say that we've got a very supportive banking group. So I do want to thank our banking group for all the support that they've given us and, obviously, with the refinancing as well. And as we said, we went out to a select number of banks. So we've halved the banking group. And with the half the banking group, we oversubscribed by more than twice. So very supportive banking group. We've had a lot of robust and -- discussions with our banks around the environmental undertakings within the facility. They are no more than what we had before. We have ongoing discussions with them in terms of working through the sustainability side of the business; the ESG commitments we have that's been outlined here today, the 25 by 25; and then obviously, moving towards FID with the CCS project as well at Moomba. So they are obviously aligned with us on all of those commitments, and we're very pleased to have them as part of the group. So from our perspective, we've really wanted to get into the market right now in terms of making use of the lower margins that's available to us and obviously sure of the balance sheet and liquidity going forward as well. But from our point of view, very supportive bank group, and looking forward to working with them going forward as well. I don't know whether that answers your question, Mark.

Yes. No, that's great. Yes. That all sounds fairly clear. I just wanted to ask one more question, perhaps for Matt, on the Perth Basin. You've obviously got some quite big targets there. And as has already been discussed on the call, South Erregulla is an important data point. How are you thinking about capital allocation with respect to this exploration, given the size of the volumes involved and the difficulty in not being able to export volumes? How many of these wells will be commitment wells as opposed to, yes, discretionary?

Yes. It's a good question, Mark. Look, there's not a lot of commitment wells that we've got there in the program, but expect that we are likely to drill a few exploration wells in the next year to 2 in the Perth Basin. The one comment I'd make is from a bang for buck perspective, this is a great place to do business. We're onshore, relatively low cost of drilling, of course, compared to being offshore. And the sizes are pretty material, and we've got infrastructure in the basin and, obviously, clearly building more infrastructure right now. So from our perspective, it is a basin that's going to make a lot of sense for us to continue to drill and explore. From a market perspective, we've talked about it before that there is a little bit of a chicken-and-egg situation here because it was a government decision, which we fully understand, appreciate, and we think it was a smart one to limit the amount of export that we could take from the Perth Basin until there's more understanding of what's the supply/demand balance going to look like. And obviously, more discoveries in the Perth Basin helped that supply-demand balance. Other offshore projects getting through FID will help that as well. So we're hopeful. We can't guarantee it, but hopeful that we'll be able to get more gas into export, but also the domestic market is strong. And also, what we're seeing is potential for other projects like petrochem. And we've got time. It's what I said earlier. We've got time to basically get our thinking straight on what the market looks like. But we're definitely not betting the farm, and we're drilling exploration mills in the Perth Basin. That's for sure.

There are no further questions at this time. I'll now hand back to Matt for closing remarks.

Great. Thank you for your attention, everyone. Obviously, there is a lot of work that goes into these presentations in these days, so I'd like to thank my own team as well for all the extensive work they've done. We have provided you with a lot of information. That's been very deliberate, so I'm sure you need to take some time to digest it all. Please feel free to call in to clarify anything you need. And we look forward to meeting with a number of you over the coming weeks to talk about it some more and answer your questions and get your insights. We think the future is exciting for Beach. Frankly, we really do. This is a plan that we set forth on a number of years ago post the Lattice acquisition. We could see what the plan was, and we are now executing on the plan, and it's getting very close to being able to come out the other side of that execution. And I think we just look like a compelling business today. I think we look even more compelling when we come out the other side of that capital program. We really do. So I appreciate your time again. Thanks for all your questions, and look forward to catching up. Thank you.